Power Delivery Systems

7/29/2019 Power Delivery Systems

http://slidepdf.com/reader/full/power-delivery-systems 1/45

1Power DeliverySystems

1.1 INTRODUCTION

Retail sale of electric energy involves the delivery of power in ready to use form to the final

consumers. Whether marketed by a local utility, load aggregator, or direct power retailer,this electric power must flow through a power delivery system on its way from power

production to customer. This transmission and distribution (T&D) system consists ofthousands of transmission and distribution lines, substations, transformers, and otherequipment scattered over a wide geographical area and interconnected so that all function inconcert to deliver power as needed to the utility's customers.

This chapter is an introductory tutorial on T&D systems and their design constraints.For those unfamiliar with power delivery, it provides an outline of the most importantconcepts. But in addition, it examines the natural phenomena that shape T&D systems andexplains the key physical relationships and their impact on design and performance. For thisreason experienced planners are advised to scan this chapter, or at least its conclusions, so

that they understand the perspective upon which the rest of the book builds.

In a traditional electric system, power production is concentrated at only a few large,

usually isolated, power stations. The T&D system moves the power from those often distant

generating plants to the many customers who consume the power. In some cases, cost canbe lowered and reliability enhanced through the use of distributed generation - numerous

smaller generators placed at strategically selected points throughout the power system inproximity to the customers. This and other distributed resources - so named because theyare distributed throughout the system in close proximity to customers - including storage

systems and demand-side management, often provide great benefit.

But regardless of the use of distributed generation or demand-side management, theT&D system is the ultimate distributed resource, consisting of thousands, perhaps millions,

of units of equipment scattered throughout the service territory, interconnected and

1

Copyright © 2004 by Marcel Dekker, Inc.



2 Chapter 1

operating in concert to achieve uninterrupted delivery of power to the electric consumers.These systems represent an investment of billions of dollars, require care and precision intheir operation, and provide one of the most basic bu ilding blocks of our society - widelyavailable, economical, and reliable energy.

This chapter begins with an examination of the role and mission of a T&D system -why it exists and what it is expected to do. Section 1.3 looks at several fundamentalphysical laws that constrain T&D systems design. The typical hierarchical system structurethat results and the costs of its equipment are summarized in sections 1.4 and 1.5. In section1.6, a number of different w ays to lay out a distribution system are covered, along with theiradvantages and disadvantages. The chapter ends with a look at the "systems approach" -

perhaps the single most important concept in the design of retail delivery systems which areboth inexpensive and reliable.

1.2 T&D SYSTEM'S MISSION

A T&D system's primary mission is to deliver power to electrical consumers at their place

of consumption and in ready-to-use form. The system must deliver power to the customers,which means it must be dispersed throughout the utility service territory in rough proportionto customer locations and demand (Figure 1.1). This is the primary requirement for a T&Dsystem, and one so basic it is often overlooked - the system must cover ground - reachingevery customer with an electrical path of sufficient strength to satisfy that customer'sdemand for electric power.

That electrical path must be reliable, too, so that it provides an uninterrupted flow of

stable power to the util ity's customers. R eliable power delivery means delivering all of thepower demanded, not ju st some of the power needed, and doing so all of the time. A nyth ingless than near perfection in meeting this goal is considered unacceptable - 99.9% reliabilityof service may sound impressive, but it means nearly nine hours of electric service

interruption each year, an amount that would be unacceptable in nearly any first-worldcountry.

2011WINTER PEAK

3442 MW

N

Te n miles

Shading indicates

relative load

density. Lines

show major roads

and highways.

Figure 1.1 Map of electrical demand for a major US city shows where the total demand of more than2,000 MW peak is located. Degree of shading indicates electric load distribution. The T&D systemmust cover the region with sufficient capacity at every location to meet the customer needs there.




3ower Delivery Systems

Table 1.1 Required Functions, or "Mission Goals" for a Power Delivery System

1. Cover the utility's service territory, reaching all consumers who wish to beconnected and purchase power.

2. Have sufficient capability to meet the peak demands of those energy

consumers.

3. Provide satisfactory continuity of service (reliability) to the connected

energy consumers.

4. Provide stable voltage quality regardless of load level or conditions.

Beyond the need to deliver power to the customer, the utility's T&D system must also

deliver it in ready-to-use form - at the utilization voltage required for electrical appliances

and equipment, and free of large voltage fluctuations, high levels of harmonics, or transient

electrical disturbances (Engel et al., 1992).

Most electrical equipment in the United States is designed to operate properly when

supplied with 60 cycle alternating current at between 114 and 126 volts, a plus or minus

five percent range centered on the nominal utilization voltage of 120 volts (RMS average

of the alternating voltage). In many other countries, utilization standards vary from 230 to

slightly over 250 volts, at either 50 or 60 cycles AC.1But regardless of the utilization

voltage, a utility must maintain the voltage provided to each customer within a narrow

range centered within the voltages that electric equipment is designed to tolerate.A ten percent range of delivery voltage throughout a utility's service area may be

acceptable, but a ten percent range of fluctuation in the voltage supplied to any one

customer is not. An instantaneous shift of even three percent in voltage causes a perceptible,

and to some people disturbing, flicker in electric lighting. More important, voltage

fluctuations can cause erratic and undesirable behavior of some electrical equipment.

Thus, whether high or low within the allowed range, the delivery voltage of any one

customer must be maintained at about the same level all the time - normally within a range

of three to six percent - and any fluctuation must occur slowly. Such stable voltage can be

difficultto obtain,

becausethe voltage at the customer end of a T&D system varies

inversely with electric demand, falling as the demand increases, rising as it decreases. If this

range of load fluctuation is too great, or if it happens too often, the customers may consider

it poor service.

Thus, a T&D system's mission is to meet the four goals in Table 1.1, and of course,

above all else, to achieve these goals at the lowest cost possible and in a safe and

esthetically acceptable manner.

1.3 RELIABILITY OF POWER DELIVERY

Reliability of service was always a priority of electric utilities, however the tone of that

focus, and the perspective on reliability began to change in the 1990s when the power

industry saw a growing emphasis on reliability of customer service. In the early part of theelectric era (1890 - 1930) most electric utilities viewed interruptions of service primarilyas

interruptions in revenue - when outages of equipment occur and the utility cannot provide

1Power is provided to customers in the United States by reversed alternating current legs (+120

volts and -120 volts wire to ground). This provides 240 volts of power to any appliance that needs

it, but for purposes of distribution engineering and performance acts like only 120 volt power.




4 Chapter 1

electric service, it earns no money (Abbott, 1895). Industry studies of outages andinterruptions during this period were almost entirely based around the "loss of revenue" thatthe utility would experience from poor reliability, and reliability was managed from thatperspective. To some extent, the view of utilities then was the same as a cable or broadcast

TV network might have today: when we aren't distributing, we aren't earning. Just as a TVnetwork knows that when its broadcast is interrupted its revenues (from advertising) are cut,so electric utilities in the first third of the 20 th century knew that when equipment was out,

they weren't earning money. Resources and actions to avoid outages were justified andmanaged from the standpoint that, to an extent, they were profitable because they kept therevenue stream coming into the utility's coffers.

During the 1930s through the 1960s, electric power came to be viewed as an essential

and needed service, and reliability came to be viewed as an obligation the utility had to itscustomers. Most utilities, including their upper management, adopted a "public

stewardship" attitude in which they viewed themselves and their company as having an

obligation to maintain power flow to their customers. However, the computer and datacollection technologies needed to collect and manage quantitative data on customer-levelreliability were not available at that time (as they are today). A widespread outage overnightmight be reported to management the next morning as "we had a lot of customers, maybe asmany as 40,000, out for quite a while, and had about sixteen crews on it all night." N o, orvery limited, reporting was done to state regulatory agencies.

2 As a result, most utilitiesused only informal means based on experience and good intentions, and sometimesmisguided intuition, to manage reliability.

Several changes occurred during the period 1970 through 2000 that led to more

quantitative emphasis on reliability. First, electric power increasingly became "missioncritical" to more and more businesses and homes. Equally important, it became possible tomeasure and track reliability of service in detail. Modern SCAD A, system monitoring,outage management, and customer information systems permit utilities to determine whichcustomer is out of service, and when, and why. Reports (see footnote 2, below) can be

prepared on individual outages and the reliability problems they cause, and on the aggregateperformance of the whole system over any period of time. Managerial study of pastperformance, and problems, could be done in detail, "slicing and dicing" the data in any

number of ways and studying it for root causes and improved ways of improving service.

Thus, the growing capability to quantitatively measure and study reliability of serviceenabled the industry to adopt much more specific and detailed managerial approaches to

reliability.Simultaneously, during the 1980s and 1990s, first-world nations adopted increasing

amounts of digital equipment. "Computerized" devices made their way into clocks, radios,

televisions, stoves, ovens, washers and dryers and a host of other household appliances.Similarly, digital systems became the staple of "efficient" manufacturing and processing

industries, withou t w hich factories could not compete on the basis of cost or quality.This dependence on digital systems raised the cost of short power interruptions. For

example, into the mid 1970s, utilities routine ly performed switching (transfer of groups of

between 100 and 2000 homes) in the very early morning hours, using "cold switching"; a

2By contrast, today management, and regulators, would receive a report more like "a series of weather-related events between 1:17 and 2:34 interrupted service to 36,512 customers, for an average of 3hours and 12 minutes each, with 22,348 of them being out for more than four hours. Seven crewsresponded to outage restoration and put in a total of 212 hours restoring service. Fifteen corrective

maintenance tickets (for permanent completion of temporary repairs made to restore service) remainto be completed as of 9 AM this morning."





Table 1.2 Summary of Power Distribution Reliability

Outages of equipment cause interruptions of service.

In most distribution systems, every distribution equipment outage causes service interruptionsbecause there is only one electrical path to every consumer.

Reliability measures are based on two characteristics:

Frequency - how often power interruptions occur

Duration - how long they last

Equity of reliability - assuring that all customers receive nearly the same level of reliability - is

often an important part of managing reliability performance.

Drops in voltage (sags) often have the same impact as complete cessation of power.

branch of a feeder would be briefly de-energized as it was disconnected from one feeder,and then energized again through closing a switch to another feeder a few seconds, orminutes, later. Such short, late night/early morning interruptions caused few customercomplaints in the era before widespread use of digital equipment. Energy consumers whoeven noticed the events were rare; analog electric clocks would fall a few seconds behind,that was all. Like the clocks, devices in "pre-digital" homes would immediately take upservice again when power was restored.

But today, a similar "cold switching" event would disable digital clocks, computers, andelectronic equipment throughout the house, leaving the homeowners to wake up (often latebecause alarms hav e no t gone off) to a house full of blinking digital displays. Surveys haveshown homeowners consider even a "blink" interruption to cause them between seven and

fifteen minutes of inconvenience, resetting clocks, etc. To accommodate this need, utilitiesmust use "hot switching" in which a switch to the new source is closed first, and the tie to

the old source is opened. This avoids creating any service interruption, but can createoperating problems by leading to circulating (loop) currents that occasionally overloadequipment.

This gradual change in the impact of brief interruptions has had even a more profound

impact on business and industry than on homeowners. In the 1930s, the outage of powerto a furniture factory meant that power saws and tools could not be used until power was

restored. The employees had to work with ambient light through windows. Productivitywould decrease, but not cease. And it returned to normal quickly once power was

restored. Today, interruption of power for even a second to most furniture factorieswould immediately shut down their five-axis milling machines and CAM-assembly

robots. Work in progress would often be damaged and lost. And after power is restoredthe CAM assembly systems may take up to an hour to re-boot, re-initialize, and re-start:

in most businesses and industries that rely on digital equipment, production is almost

always interrupted for a longer period than the electrical service interruption itself.Thus, by the 1990s, consumers (and thus regulators) paid somewhat more attention to

service interruptions, particularly short duration interruptions. But it would be far toosimplistic to attribute the increasing societal emphasis on power reliability only to the use ofdigital equipment. The "digital society" merely brought about an increasing sensitivity to

very short interruptions. In the bigger sense, the need for reliable electric power grewbecause society as a whole came to rely much more on electric power, period. Had digitalequipment never been invented, if the world were entirely analog, there would still be the




6 Chapter 1

same qualitative emphasis on reliab ility. Specific attention to "blinks" and short-terminterruptions migh t receive som ewhat less attention, and longer duration interruptions a bit

more, than what actually occurs today. But overall, reliability of power would be just ascrucial for businesses and private individuals. For these reasons, the power industry began

to move toward quantitative, pro-active management of power system reliability: settargets, plan to achieve them, monitor progress, and take corrective actions as needed.

The most salient points about power system reliability are summarized in Table 1.2.Chapters 4,7, 8, 14, 21, 23 , and 28 will discuss reliability and its planning and managementin much further detail.

1.4 THE "NATURAL LAWS OF T&D"

The complex interaction of a T&D system is governed by a number of physical lawsrelating to the natural phenomena that hav e been harnessed to produce and move electricpower. These interactions have created a number of "truths" that dominate the design of

T&D systems:

1. It is more economical to move power at high voltage. The higher the voltage, thelower the cost per kilowatt to move power any distance.

2. The higher the voltage, the greater the capacity and the greater the cost ofotherwise similar equipment. Thus, high voltage lines, while potentiallyeconomical, cost a great deal more than low voltage lines, but have a muchgreater capacity. They are only economical in practice if they can be used tomove a lot of power in one block - they are the giant economy size, but whilealways giant, they are only economical if one truly needs the giant size.

3. Utilization voltage is useless for the transmission of power. The 120/240 voltsingle-phase utilization voltage used in the United States, or even the 250volt/416 volt three-phase used in "European systems" is not equal to the task of

economically mo ving power more than a few hundred yards. The application ofthese lower voltages for anything more than very local distribution at theneighborhood level results in unacceptably high electrical losses, severe voltage

drops, and astronomical equipment cost.4. It is costly to change voltage level - not prohibitively so, for it is done throughout

a power system (that's what transformers do) - but voltage transformation is a

major expense which does nothing to move the power any distance in and ofitself.

5. Power is more economical to produce in very large amounts. Claims by theadvocates of modern distributed generators notwithstanding, there is a significanteconomy of scale in generation - large generators produce power moreeconomically than small ones. Thus, it is most efficient to produce power at a

few locations utilizing large generators.3

3 The issue is more complicated than just a comparison of the cost of big versus small generation. Insome cases, distributed generation provides the lowest cost overall, regardless of the economy ofscale, due to constraints imposed by the T&D system. Being close to the customers, distributedgeneration does not require T&D facilities to move the power from generation site to customer.


http://dk1341ch4.pdf/

















Power Delivery Systems 7

6. Power must be delivered in relatively small quantities at a low (120 to 250 volt)

voltage level. The average customer has a total demand equal to only 1/10,000 or

1/100,000 of the output of a large generator.

An economical T&D system builds upon these concepts. It must "pick up" power at afew, large sites (generating plants) and deliver it to many, many more small sites

(customers). It must somehow achieve economy by using high voltage, but only when

power flow can be arranged so that large quantities are moved simultaneously along a

common path (line). Ultimately, power must be subdivided into "house-sized" amounts,

reduced to utilization voltage, and routed to each business and home via equipment whose

compatibility with individual customer needs means it will be relatively quite inefficientcompared to the system as a whole.

Hierarchical Voltage Levels

The overall concept of a power delivery system layout that has evolved to best handle these

needs and "truths" is one of hierarchical voltage levels as shown in Figure 1.2.

As power is moved from generation (large bulk sources) to customer (small demand

amounts) it is first moved in bulk quantity at high voltage - this makes particular sense

since there is usually a large bulk amount of power to be moved out of a large generating

plant. As power is dispersed throughout the service territory, it is gradually moved down to

lower voltage levels, where it is moved in ever smaller amounts (along more separate paths)

on lower capacity equipment until it reaches the customers. The key element is a "lower

voltage and split" concept.Thus, the 5 kW used by a particular customer - Mrs. Rose at 412 Oak Street in

Metropolis City - might be produced at a 750 MW power plant more than three hundred

miles to the north. Her power is moved as part of a 750 MW block from plant to city on a

345 kV transmission line to a switching substation. Here, the voltage is lowered to 138 kV

through a 345 to 138 kV transformer, and immediately after that the 750 MW block is

• 345 kV transmission

•" 138 kV transmission

— 12.47 kVprimary feeder

120/240 volt secondary

I ] switching substation

Qsubstation

• servicetransformer

Figure 1.2 A power system is structured in a hierarchical manner with various voltage levels. A keyconcept is "lower voltage and split" which is done from three to five times during the course of power

flow from generation to customer.




8 Chapter 1

split into five separate flows in the switching substation busw ork, each of these five partsbeing roughly 150 MW. N ow part of a smaller block of power, Mrs. Rose's electricity isrouted to her side of M etropolis on a 138 kV transmission line that snakes 20 miles through

the northern part of the city , ultimately connecting to another switch ing substation. This 138

kV transmission line feeds power to several distribution substations along its route,

4

amongwhich it feeds 40 M W into the substation that serves a number of neighborhoods, includingMrs. Rose's. Here, her power is run through a 138 kV/12.47 kV distribution transformer.

As it emerges from the low side of the substation distribution transformer at 12.47 kV(the primary distribution voltage) the 40 MW is split into six parts, each about 7 MW, witheach 7 MV A part routed onto a different distribution feeder. Mrs. Rose's power flows alongone particular feeder for two miles, until it gets to within a few hundred feet of her home.Here, a much smaller amount of power, 50 kVA (sufficient for perhaps ten homes), isrouted to a service transformer, one of several hundred scattered up and down the length ofthe feeder. As Mrs. Rose's power flows through the service transformer, it is reduced to120/240 volts. As it emerges, it is routed onto the secondary system, operating at 120/240

volts (250/416 volts in Europe and ma ny other countries). The secondary wiring splits the50 kVA into small blocks of power, each about 5 kVA, and routes one of these to Mrs.Rose's home along a secondary conductor to her service drops - the wires leading directlyto her house.

Over the past one hundred years, this hierarchical system structure has proven a mosteffective way to move and distribute power from a few large generating plants to a widelydispersed customer base. The key element in this structure is the "reduce voltage and split"function - a splitting of the power flow being done essentially simultaneously with a

reduction in voltage. U sua lly, this happens between three and five times as power m akes itsway from generator to customers.

1.5 LEVELS OF THE T&D SYSTEM

As a consequence of this hierarchical structure of power flow from power production toenergy consumer, a power delivery system can be thought of very conveniently ascomposed of several distinct levels of equipment, as illustrated in Figure 1.3. Each levelconsists of man y units of fundamentally similar equipment, doing roughly the same job, bu t

located in different parts of the system so as to "cover" the entire utility service territory.For example, all of the distribution substations are planned and laid out in approximatelythe same manner and do roughly the same job. All are composed of roughly similar

equipment doing the same job. Some substations might be "larger" than others in bothphysical and capability terms - one could have four 50 MVA transformers and associatedequipment, another only one 7 MVA transformer. But both perform the same function fortheir area of the system, taking incoming power from sub-transmission, lowering voltage,splitting the power flow, and routing it onto distribution feeders for delivery in theneighborhoods around them. These constitute a "level" of the system, because all the power

delivered everywhere flows through one such substation; in every part of the utility system,

there is a "local" substation whose function is to provide the power for the neighborhoodsaround it. Together, these substations constitute the "substation level" of the system. Theirservice areas fit together in a mosaic, each covering its piece of the service territory.

4 Transmission lines whose sole or major function is to feed power to distribution substations are often

referred to as "sub-transmission" lines.





Transmission

Service/Secondary

Customer

Figure 13 A T&D system consists of several levels of power delivery equipment, each feeding the

one below it.




10 Chapter 1

Likewise, the feeders the substations route power into are all similar in equipment

type, layout, and mission, and all service transformers to which those feeders route power

are similarly serving the same basic mission and are designed with similar planning goals

and to similar engineering standards.

Thus, power can be thought of as flowing "down" through these various levels, on itsway from power production and the wholesale grid to the energy consumers. As it moves

from the generation plants (system level) to the energy consumers, the power travels

through the transmission level, to the sub-transmission level, to the substation level, onto

and through the primary feeder level, and onto the secondary service level, where it finally

reaches the customer. Each level takes power from the next higher level in the system and

delivers it to the next lower level in the system. In almost all cases each flow of power is

split into several paths at or shortly after the transition down to the next level.

While each level varies in the types of equipment it has, its characteristics, mission, and

manner of design and planning all share several common characteristics:

• Each level is fed power by the one above it, in the sense that the next higher level

is electrically closer to the generation.

• Both the nominal voltage level and the average capacity of equipment drops from

level to level, as one moves from generation to customer. Transmission lines

operate at voltages of between 69 kV and 1,100 kV and have capacities between

50 and 2,000 MW. By contrast, distribution feeders operate between 2.2 kV and

34.5 kV and have capacities somewhere between 2 and 35 MW.

• Each level has many more pieces of equipment in it than the one above. A system

with several hundred thousand customers might have fifty transmission lines, one

hundred substations, six hundred feeders, and forty thousand service

transformers.

• As a result, the net capacity of each level (number of units times average size)

increases as one moves toward the customer. A power system might have 4,500

MVA of substation capacity but 6,200 MVA of feeder capacity and 9,000 MVA

of service transformer capacity installed.5

• Reliability drops as one moves closer to the customer. A majority of service

interruptions are a result of failure (either due to aging or to damage from severe

weather) of transformers, connectors, or conductors very close to the customer, as

shown in Figure 1.4.

Table 1.3 gives statistics for a typical system. The net effect of the changes in average

size and number of units is that each level contains a greater total capacity than the level

above it - the service transformer level in any utility system has considerably more installed

capacity (number of units times average capacity) than the feeder system or the substation

system. Total capacity increases as one heads toward the customer because of non-

coincidence of peak load (which will be discussed in Chapter 3) and for reliability purposes.

5This greater-capacity-at-every-lower-level characteristic is a deliberate design feature of most power

systems, and required both for reliability reasons and to accommodate coincidenceof load, which willbe discussed in Chapter 3.








Ten-year Service Interruption

Statistics by Level of Cause15

io

E —>

Oo

Generation Trans. Subs. Feeders Service

Level of the Power System

Figure 1.4 Ten years of customer interruptions for a large electric system, grouped by level of cause.

Interruptions due to generation and transmission often receive the most attention because they usuallyinvolve a large number of customers simultaneously. However, such events are rare whereas failures

and interruptions at the distribution level create a constant background level of interruptions.

Table 13 Equipment Level Statistics for a Medium-Sized Electric System

Level Voltage Number Avg. Cap. Total Cap

of System kV of Units MVA MVA

Transmission

Sub-transmission

Substations

FeedersService Trans.Secondary/ServiceCustomer

345, 138138, 69139/23.9, 69/13.8

23.9, 13.8.12, .24

.12, .24

.12

122545

22760,000

250,000

250,000

1506544

11.05

.014

.005

1,400

1,5251,980

2,497

3,000

3,500

1,250

Figure 1.5 A network is an electrical system with more than one path between any two points,meaning that (if properly designed) it can provide electrical service even if any one element fails.




12 Chapter 1

The Transmission Level

The transmission system is a network of three-phase lines operating at voltages generallybetween 115 kV and 765 kV . Capacity of each line is between 50 M VA and 2,000 MVA.The term "network" means that there is more than one electrical path between any two

points in the system (Figure 1.5). N etworks are laid out in this manner for reasons of

reliability and operating flow - if any one element (line) fails, there is an alternate route and

power flow is (hopefully) no t interrupted.In addition to their function in moving power, portions of the transmission system - the

largest elements, namely its major power delivery lines - are designed, at least in part, for

stability needs. The transm ission grid provides a strong electrical tie between generators, sothat each can stay synchronized with the system and with the other generators. Thisarrangement allows the system to operate and to function evenly as the load fluctuates andto pick up load smoothly if any generator fails - what is called stability of operation. (A

good deal of the equipment put into transmission system design, and much of its cost, is forthese stability reasons, not solely or even mainly for moving pow er.)

The Sub-Transmission Level

The sub-transmission lines in a system take power from the transmission switching stationsor generation plants and deliver it to substations along their routes. A typical sub-

transmission line may feed power to three or more substations. Often, portions of thetransmission system - bulk power delivery lines, lines designed at least in part for stabilityas well as power delivery needs - do this too, and the distinction between transmission and

sub-transmission lines becomes rather blurred.N ormally, sub-transmission lines are in the range of capacity of 30 M VA up to perhaps

250 MVA, operating at voltages from 34.5 kV to as high as 230 kV. With occasionalexceptions, sub-transmission lines are part of a network grid - they are part of a system in

which there is more than one route between any two points. Usually, at least two sub-transmission routes flow into any one substation, so that feed can be maintained if one

fails.6

The Substation Level

Substations, the meeting points between the transmission grid and the distribution feedersystem, are where a fundamental change takes place within most T&D systems. Thetransmission and sub-transmission systems above the substation level usually form anetwork, as discussed above, with more than one power flow path between any two parts.But from the substation on to the customer, arranging a network configuration wouldsimply be proh ibitive ly expensive. Thus, most distribution systems are radial - there is onlyone path through the other levels of the system.

Typically, a substation occupies an acre or more of land, on w hich the various necessarysubstation equipment is located. Substation equipment consists of high and low voltage

racks and busses for the power flow, circuit breakers for both the transmission anddistribution level, metering equipment, and the "control house," where the relaying,measurement, and control equipment is located. But the most important equipment - whatgives this substation its capacity rating, are the substation transformers, wh ich convert the

6 Radial feed — only one line ~ is used in isolated, expensive, or difficult transmission situations,but for reliability reasons is not recomm ended.





incoming power from transmission voltage levels to the lower primary voltage for

distribution.

Individual substation transformers vary in capacity, from less than 10 MVA to as much

as 150 MVA. They are often equipped with tap-changing mechanisms and control

equipment to vary their windings ratio so that they maintain the distribution voltage withina very narrow range, regardless of larger fluctuations on the transmission side. The

transmission voltage can swing by as much as 5%, but the distribution voltage provided on

the low side of the transformer stays within a narrow band, perhaps only ± .5%.

Very often, a substation will have more than one transformer. Two is a common

number, four is not uncommon, and occasionally six or more are located at one site. Having

more than one transformer increases reliability - in an emergency, a transformer can handle

a load much over its rated load for a brief period (e.g., perhaps up to 140% of rating for up

to four hours). Thus, the T&D system can pick up the load of the outaged portions during

brief repairs and in emergencies.

Equipped with from one to six transformers, substations range in "size" or capacity from

as little as five MVA for a small, single-transformer substation, serving a sparsely

populated rural area, to more than 400 MVA for a truly large six-transformer station,

serving a very dense area within a large city.

Often T&D planners will speak of a transformer unit, which includes the transformerand all the equipment necessary to support its use - "one-fourth of the equipment in a four-

transformer substation." This is a much better way of thinking about and estimating cost for

equipment in T&D plans. For while a transformer itself is expensive (between $50,000 and

$1,000,000); the buswork, control, breakers, and other equipment required to support its use

can double or triple that cost. Since that equipment is needed in direct proportion to thetransformer's capacity and voltage, and since it is needed only because a transformer is

being added, it is normal to associate it with the transformer as a single planning unit - add

the transformer, add the other equipment along with it.

Substations consist of more equipment, and involve more costs, than just the electrical

equipment. The land (the site) has to be purchased and prepared. Preparation is non-trivial.

The site must be excavated, a grounding mat (wires running under the substation to protect

against an inadvertent flow during emergencies) laid down, and foundations and control

ducting for equipment must be installed. Transmission towers to terminate incoming

transmission must be built. Feeder getaways - ducts or lines to bring power out to thedistribution system - must be added.

The Feeder Level

Feeders, typically either overhead distribution lines mounted on wooden poles or

underground buried or ducted cable sets, route the power from the substation throughout its

service area. Feeders operate at the primary distribution voltage. The most common primary

distribution voltage in use throughout North America is 12.47 kV, although anywhere from

4.2 kV to 34.5 kV is widely used. Worldwide, there are primary distribution voltages as low

as 1.1 kV and as high as 66 kV. Some distribution systems use several primary voltages -for example 23.9 kV and 13.8 kV and 4.16 kV.

A feeder is a small transmission system in its own right, distributing between 2 MVA to

more than 30 MVA, depending on the conductor size and the distribution voltage level.

Normally between two and 12 feeders emanate from any one substation, in what has been

called a dendritic configuration — repeated branching into smaller branches as the feeder

moves out from the substation toward the customers. In combination, all the feeders in a




14 Chapter 1

power system constitute the feeder system (Figure 1.6). An average substation has between

two and eight feeders, and can vary between one and forty.The m ain, three-phase trunk of a feeder is called the primary trunk and may branch into

several main routes, as shown in the diagram. These main branches end at open points

where the feeder meets the ends of other feeders - points at which a normally open switchserves as an emergency tie between two feeders.

In addition, each feeder will be divided, by normally closed switches, into severalswitchable elements. During emergencies, segments can be re-switched to isolate damagedsections and route power around outaged equipment to customers who would otherwisehave to remain out of service until repairs w ere made.

By definition, the feeder consists of all primary voltage level segments between thesubstations and an open point (switch). Any part of the distribution level voltage lines -

three-phase, two-phase, or single-phase - that is switchable is considered part of the

primary feeder. The primary trunks and switchable segments are usually built using threephases, with the largest size of distribution conductor (typically this is about 500-600 MCMconductor, but conductor over 1,000 MCM is not uncommon, and the author has designedand built feeders for special situations with up to 2,000 MCM conductor) justified for

reasons other than maximum capacity (e.g., contingency switching). Often a feeder hasexcess capacity because it needs to provide back-up for other feeders during emergencies.

The vast majority of distribution feeders worldwide and within the United States areoverhead construction, wooden pole with wooden crossarm or post insulator. Only in denseurban areas, or in situations where esthetics are particularly important, can the higher cost

of underground construction be justified. In this case, the primary feeder is built from

insulated cable, which is pulled through concrete ducts that are first buried in the ground.Underground feeder costs from three to ten times what overhead does.

Many times, however, the first several hundred yards of an overhead primary feeder arebuilt underground even if the system is overhead. This underground portion is used as thefeeder getaway. Particularly at large substations, the underground getaway is dictated bypractical necessity, as well as by reliability and esthetics. At a large substation, ten or 12

fj substation• closed switcho open switch

— primary trunk

— lateral branchesThree miles

Figure 1.6Distribution feeders route power away from the substation, as shown (in idealized form -

configuration is never so evenly symmetric in the real world) for two substations. Positions ofswitches make the system electrically radial, while parts of it are physically a network. Shown here aretwo substations, each with four feeders.





three-phase, overhead feeders leaving the substation mean from 40 to 48 wires hanging inmid-air around the substation site, with each feeder needing the proper spacings forelectrical insulation, safety, and maintenance. At a large-capacity substation in a tightlocation, there is simply not enough overhead space for so many feeders. Even if there is,

the resulting tangle of wires looks unsightly and, perhaps most important, is potentiallyunreliable - one broken wire falling in the wrong place can disable a lot of power deliverycapability.

The solution to this dilemma is the underground feeder getaway, usually consisting ofseveral hundred yards of buried, ducted cable that takes the feeder out to a riser pole, whereit is routed above ground and connected to overhead wires. Very often, this initialunderground link sets the capacity limit for the entire feeder - the underground cableampacity is the limiting factor for the feeder's power transmission.

The Lateral Level

Laterals, short stubs or line segments that branch off the primary feeder, represent the finalprimary voltage part of the power's journey from the substation to the customer. A lateral is

directly connected to the primary trunk and operates at the same nominal voltage. A series

of laterals tap off the primary feeder as it passes through a community, each lateral routingpower to a few dozen homes.

N ormally, laterals do not have branches, and many laterals are only one- or two-phase -

all three phases are used only if a relatively substantial amount of power is required, or ifthree-phase service must be provided to some of the customers. N ormally, single- and two-phase laterals are arranged to tap alternately different phases on the primary feeder, as

shown below, in an attempt by the distribution planning engineer to balance the loads asclosely as possible.

Typically, laterals deliver from as little as 10 kV A for a small single-phase lateral to asmuch as 2 MVA. In general, even the largest laterals use small conductors (relative to theprimary size). When a lateral needs to deliver a great deal of power, the planner willnormally use all three phases, with a relatively small conductor for each, rather than employa single-phase and use a large conductor. This approach avoids creating a significantimbalance in loading at the point where the lateral taps into the primary feeder. Power flow,loadings, and voltage are maintained in a more balanced state if the power demands of a

"large lateral" are distributed over all three phases.Laterals (wooden poles) are built overhead or underground. Unlike primary feeders andtransmission lines, single-phase laterals are sometimes buried directly. In this case, the

cable is placed inside a plastic sheath (that looks and feels much like a vacuum cleanerhose), a trench is dug, and the sheathed cable is unrolled into the trench and buried. Directlyburied laterals are no more expensive than underground construction in many cases.

The Service Transformers

Service transformers lower voltage from the primary voltage to the utilization or customervoltage, normally 120/240 volt two-leg service in most power systems throughout N orthAmerica. In overhead construction, service transformers are pole mounted and single-phase, between 5 kV A and 166 kV A capacity. There may be several hundred scatteredalong the trunk and laterals of any given feeder; since power can travel efficiently only upto about 200 feet at utilization voltage, there must be at least one service transformerlocated reasonably close to every customer.

Passing through these transformers, power is lowered in voltage once again, to the finalutilization voltage (120/240 volts in the United States) and routed onto the secondarysystem or directly to the customers. In cases where the system is supplying power to large




16 Chapter 1

commercial or industrial customers, or the customer requires three-phase power, between

two and three transformers may be located together in a transformer bank and

interconnected in such a way as to provide multi-phase power. Several different connection

schemes are possible for varying situations.

Underground service, as opposed to overhead pole-mounted service, is provided bypadmount or vault type service transformers. The concept is identical to overhead

construction, with the transformer and its associated equipment changed to accommodate

incoming and outgoing lines that are underground.

The Secondary and Service Level

Secondary circuits, fed by the service transformers, route power at utilization voltage within

very close proximity to the customer, usually in an arrangement in which each transformer

serves a small radial network of utilization voltage secondary and service lines, which lead

directly to the meters of customers in the immediate vicinity.

At most utilities, the layout and design of the secondary level is handled through a set of

standardized guidelines and tables, which are used by engineering technicians and clerks to

produce work orders for the utilization voltage level equipment. In the United States, the

vast majority of this system is single-phase. In European systems, much of the secondary is

three-phase, particularly in urban and suburban areas.

What Is Transmission and What Is Distribution?

Definitions and nomenclature defining "transmission" and "distribution" vary greatly

among different countries, companies, and power systems. Traditionally, three types of

distinction between the two were made:

By voltage class: transmission is anything above 34.5 kV; distribution is

anything below that.

By function: distribution includes all utilization voltage equipment, plus all

lines that feed power to service transformers.

By configuration: transmission includes a network; distribution is all the

radial equipment in the system.

Generally, all three definitions applied simultaneously, since in most utility systems, anytransmission above 34.5 kV was configured as a network, and did not feed service

transformers directly, while all distribution was radial, built of only 34.5 kV or below, and

did feed service transformers. Substations - the meeting places of transmission lines

(incoming) and distribution lines (outgoing) - were often included in one or the other

category, but were sometimes considered as separate entities.

Today, the terms are evolving to somewhat different meanings. 'Transmission" is

becoming synonymous with "wholesale level grid" while "distribution" means the "retail"

or "service to native load" level. Chapter 30, section 2, provides a discussion of modern

interpretations and their use.

1.6 UTILITY DISTRIBUTION EQUIPMENT

The preceding section made it clear that a power delivery system is a very complex entity,

composed of thousands, perhaps even millions, of components which function together as a

T&D system. Each unit of equipment has only a small part to play in the system, and is only

a small part of the cost, yet each is critical for satisfactory service to at least one or more

customers, or it would not be included in the system.








T&D system planning is complex because each unit of equipment influences the

electrical behavior of its neighbors, and must be designed to function well in conjunction

with the rest of the system under a variety of different conditions, regardless of shifts in the

normal pattern of loads or the status of equipment nearby. While the modeling and analysis

of a T&D system can present a significant challenge, individually its components arerelatively simple to understand, engineer, and plan. In essence, there are only two major

types of equipment that perform the power delivery function:

• transmission and distribution lines, which move power from one

location to another

• transformers, which change the voltage level of the power

Added to these three basic equipment types are two categories of equipment used for

a very good reason:

• protective equipment, which provides safety and "fail safe" operation

• voltage regulation equipment, which is used to maintain voltage within an

acceptable range as the load changes. This monitoring and control

equipment is used to measure equipment and system performance and feed

this information to control systems so that the utility knows what the system

is doing and can control it, for both safety and efficiency reasons.

Transmission and Distribution Lines

By far the most omnipresent part of the power distribution system is the portion devoted to

actually moving the power flow from one point to another. Transmission lines, sub-

transmission lines, feeders, laterals, secondary and service drops all consist of electrical

conductors, suitably protected by isolation (transmission towers, insulator strings, and

insulated wrappings) from voltage leakage and ground contact. It is this conductor that

carries the power from one location to another.

Electrical conductors are available in various capacity ranges, with capacity generally

corresponding to the metal cross section (other things being equal, a thicker wire carries

more power). Conductors can be all steel (rare, but used in some locations where winter iceand wind loadings are quite severe), all aluminum, copper, or a mixture of aluminum and

steel. Underground transmission can use various types of high-voltage cable. Capacity of a

line depends on the current-carrying capacity of the conductor or the 'cable, the voltage, the

number of phases, and constraints imposed by the line's location in the system.

The most economical method of handling a conductor is to place it overhead, supported

by insulators, on wooden poles or metal towers, suitably clear of interference or contact

with persons or property. However, underground construction, while generally more costly,

avoids esthetic intrusion of the line and provides some measure of protection from weather

(it also tends to reduce the capacity of a line slightly due to the differences between

underground cable and overhead conductor). Suitably wrapped with insulating material inthe form of underground cable, the cable is placed inside concrete or metal ducts or

surrounded in a plastic sheath.

Transmission/sub-transmission lines are always three-phase - three separate conductors

for the alternating current - sometimes with a fourth neutral (unenergized) wire. Voltage is

measured between phases - a 12.47 kV distribution feeder has an alternating current

voltage (RMS) of 12,470 volts as measured between any two phases. Voltage between any

phase and ground is 7,200 volts (12.47 divided by the square root of three). Major portions




18 Chapter 1

of a distribution system - trunk feeders - are as a rule built as three-phase lines, but lower-capacity portions may be bu ilt as either two-phase, or single-phase.7

Regardless of type or capacity, every electrical conductor has an impedance (aresistance to electrical flow through it) that causes voltage drop and electrical losses

whenever it is carrying electric power. Voltage drop is a reduction in the voltage betweenthe sending and receiving ends of the power flow. Losses are a reduction in the net power,

and are proportional to the square of the power. Double the load and the losses increase byfour. Thus, 100 kilowatts at 120 volts might go in one end of a conductor, only to emerge at

the other as 90 kilowatts at 114 volts at the other end. Both voltage drop and losses vary indirect relation to load - within very fine limits if there is no load, there are no losses or

voltage drop. Voltage drop is proportional to load - double the load and voltage dropdoubles. Losses are quadratic, however - double the load and losses quadruple.

Transformers

At the heart of any alternating power system are transformers. They change the voltage andcurrent levels of the power flow, maintaining (except for a very small portion of electricallosses) the same overall power flow. If voltage is reduced by a factor of ten from high tolow side, then current is multiplied by ten, so that their overall product (voltage timescurrent equals power) is constant in and out.

Transformers are available in a diverse range of types, sizes, and capacities. They areused within power systems in four major areas: at power plants, where power which is

minimally generated at about 20,000 volts is raised to transmission voltage (100,000 voltsor higher); at switch ing stations, where transm ission voltage is changed (e.g., from 345,000

volts to 138,000 volts before splitting onto lower voltage transmission lines); at distributionsubstations, where incom ing transmission-level voltage is reduced to distribution voltagefor distribution (e.g., 138 kV to 12.47 kV); and at service transformers, where power isreduced in voltage from the primary feeder voltage to utilization level (12.47 kV to 120/240

volts) for routing into customers' homes and businesses.Larger transformers are generally built as three-phase units, in which they

simultaneously transform all three phases. Often these larger units are built to custom or

special specifications, and can be quite expensive - over $3,000,000 per unit, in some cases.Smaller transformers, particularly most service transformers, are single-phase - it takes

three installed side by side to handle a full three-phase line's power flow. They aregenerally bu ilt to standard specifications and bought in quantity.

Transformers experience two types of electrical losses - no-load losses (often calledcore, or iron, losses) and load-related losses. N o-load losses are electrical losses inherent inoperating the transformer - due to its creation of a magnetic field inside its core - and occur

simply because the transformer is connected to an electrical power source. They areconstant, regardless of whether the power flowing through the transformer is small or large.Core losses are typically less than one percent of the nameplate rating. Only when thetransformer is seriously overloaded, to a point well past its design range, will the core losses

change (due to magnetic saturation of the core).Load-related losses a re due to the current flow through the transformer's impedance andcorrespond very directly with the level of power flow - like those of conductors and cablesthey are proportional to current squared, quadrupling whenever power flow doubles. Theresult of both types of losses is that a transformer's losses vary as the power transmittedthrough it varies, bu t always at or above a minimum level set by the no-load losses.

7 In most cases, a single-phase feeder or lateral has two conductors: the phase conductor and the neutral.





Switches

Occasionally, it is desirable to be able to vary the connection of line segments within apower delivery system, particularly in the distribution feeders. Switches are placed at

strategic locations so that the connection between two segments can be opened or closed.Switches are planned to be normally closed (NC) or normally open (NO), as was shown inFigure 1.6.

Switches vary in their rating (how much current they can vary) and their load break

capacity (how much current they can interrupt, or switch off), with larger switches beingcapable of opening a larger current. They can be manually, automatically, or remotelycontrolled in their operation.

Protection and Protective Equipment

When electrical equipment fails, for example if a line is knocked down during a storm, thenormal function of the electrical equipment is interrupted. Protective equipment is designed

to detect these conditions and isolate the damaged equipment, even if this meansinterrupting the flow of power to some customers. Circuit breakers, sectionalizers, andfused disconnects, along with control relays and sensing equipment, are used to detect

unusual conditions and interrupt the power flow whenever a failure, fault, or other

unwanted condition occurs on the system.

These devices and the protection engineering required to apply them properly to the

power system are not the domain of the utility planners and will not be discussed here.

Protection is vitally important, but the planner is sufficiently involved with protection if heor she produces a system design that can be protected within standards, and if the cost ofthat protection has been taken into account in the budgeting and planning process. Both ofthese considerations are non-trivial.

Protection puts certain constraints on equipment size and layout - for example in somecases a very large conductor is too large (because it would permit too high a short circuitcurrent) to be protected safely by available equipment and cannot be used. In other cases,

long feeders are too long to be protected (because they have too low a short circuit currentat the far end). A good deal of protective equipment is quite complex, containing sensitive

electro-mechanical parts (many of which move at high speeds and in a split-second manner)

and depending on precise calibration and assembly for proper function. As a result, the costof protective equipment and control, and the cost of its maintenance, is often significant -

differences in protection cost can make the deciding difference between two plans.

Voltage Regulation

Voltage regulation equipment includes line regulators and line drop compensators, as well

as tap changing transformers. These devices vary their turns ratio (ratio of voltage in tovoltage out) to react to variations in voltage drop - if voltage drops, they raise the voltage;if voltage rises, they reduce it to compensate. Properly used, they can help maintain voltage

fluctuation on the system within acceptable limits, but they can only reduce the range offluctuation, not eliminate it altogether.

Capacitors

Capacitors are a type of voltage regulation equipment. By correcting power factor they can

improve voltage under many heavy loads (hence large voltage drop) cases. Power factor is

a measure of how well voltage and current in an alternating system are in step with one

another. In a perfect system, voltage and current would alternately cycle in conjunction with




20 Chapter 1

one another — reaching a peak, then reaching a minimum, at precisely the same times. But

on distribution systems, particularly under heavy load conditions, current and voltage fall

out of phase - both continue to alternate 60 times a second, but during each cycle voltage

may reach its peak slightly ahead of current - there is a slight lag of current versus voltage,

as shown in Figure 1.7.It is the precise, simultaneous peaking of both voltage and current that delivers

maximum power. If out of phase, even by a slight amount, effective power drops, as does

power factor - the ratio of real (effective) power to the ma xim um possible power (if voltage

and current were locked in step).Power engineers refer to a quantity called VAR (Volt-Amp Reactive) that is caused by

this condition. Basically, as power factors worsen (as voltage and current fall farther apartin terms of phase angle) a larger percent of the electrical flow is VARs, and a smaller part is

real power. T he frus trating thin g is that the voltage is still there, and the current is still there,but because of the shift in their timing, they produce only VARs, not power. The worse thepower factor, the higher the VAR content. Poor power factor creates considerable cost and

performance consequences for the pow er system: large conductor is still required to carrythe full level of current even though power delivery has dropped, and because current ishigh, the voltage drop is high, too, further degrading quality of service.

Unless one has w orked for some time with the complex variable mathematics associated

with AC power flow analysis, VA Rs are difficult to picture. A useful analogy is to think ofVARs as "electrical foam." If one tried to pump a highly carbonated soft drink through a

system of pipes, turbulence in the pipes, particularly in times of high demand (high flow)would create foam. The foam would take up room in the pipes, but contribute little of value

to the net flow - the equivalent of VARs in an electrical system.Poor power factor has several causes. Certain types of loads create VARs - in simple

terms loads which cause a delay in the current with respect to voltage as it flows throughthem. Among the worst offenders are induction motors, particularly small ones as almostuniversally used for blowers, air conditioning compressors, and the powering of conveyorbelts and similar machinery. Under heavy load conditions, voltage and current can get outof phase to the point that power factor can drop below 70%. In addition, transmissionequipment itself can often create this lag and "generate" a low power factor.

VOLTAGE VOLTAGE

}Time f \ f-> Time

> Time i-1 4 * Time

CURRENT CURRENT

Figure 1.7 Current and voltage in phase deliver maximum power (left). If current and voltage fall outof phase (right), actual power delivered drops by very noticeable amounts - thepower factor falls.





Capacitors correct the poor power factor. They "inject" VARs into a T&D line to bringpower factor close to 1.0, transform ing VAR flow back into real power flow, regaining theportion of capacity lost to poor power factor. Capacitors can involve considerable costdepending on location and type. They tend to do the most good if put on the distribution

system, near the customers, but they cost a great deal more in those locations than ifinstalled at substations.

1.7 T&D COSTS

A T&D system can be expensive to design, build, and operate. Equipment at every levelincurs two types of costs. Capital costs include the equipment and land, labor for sitepreparation, construction, assembly and installation, and any other costs associated withbuilding and putting the equipment into operation. Operating costs include labor andequipment for operation, maintenance and service, taxes and fees, as well as the value of the

power lost to electrical losses. Usually , capital cost is a one-time cost (once i t's built, themoney's been spent). Operating costs are continuous or periodic.

Electrical losses vary depending on load and conditions. While these losses are small bycomparison to the overall power being distributed (seldom more than 8%), they constitute avery real cost to the utility, and the present worth of the lifetime losses through a majorsystem component such as a feeder or transformer can be a significant factor impacting itsdesign and specification, often more than the original capital cost of the unit. Frequently, amore costly type of transformer will be selected for a certain application because its designleads to an overall savings due to lower losses, or a larger capacity line (larger conductor)

will be used than really needed due to capacity requirements, purely because the largerconductor will incur lower losses costs.Cumulatively, the T&D system represents a considerable expense. While a few

transmission lines and switching stations are composed of large, expensive, and purpose-designed equipment, the great portion of the sub-transmission-substation-distributionsystem is built from "small stuff' - commodity equipment bought mostly "off the shelf to

standard designs. Individually inexpensive, they amount to a significant cost when addedtogether.

Transmission Costs

Transmission line costs are based on a per mile cost and a termination cost at either end ofthe line associated with the substation at which it is terminated. Costs can run from as lowas $50,000/mile for a 46 kV wooden pole sub-transmission line with perhaps 50 MVAcapacity ($1 per kVA-mile) to over $1,000,000 per mile for a 500 kV double circuitconstruction w ith 2,000 MVA capacity ($.5/kVA-mile).

Substation Costs

Substation costs include all the equipment and labor required to build a substation,

including the cost of land and easements/ROW. For planning purposes, substations can bethought of as having four costs:

1. Site cost - the cost of buying the site and preparing it for a substation.

2. Transmission cost - the cost of terminating the incoming sub-transmissionlines at the site.




22 Chapter 1

3. Transformer cost - the transformer and all metering, control, oil spillcontainment, fire prevention, cooling, noise abatement, and othertransformer related equipment, along with typical buswork, switches,metering, relaying, and breakers associated with this type of transformer,

and their installation .

4. Feeder buswork/getaway costs - the cost of beginning distribution at the

substation, includ es getting feeders out of the substation.

Often, as an expedient in planning, estimated costs of feeder busw ork and getaways arefolded into the transformer costs. The feeders to route power out of the substation areneeded in conjunction with each transformer, and in direct proportion to the transformercapacity installed, so that their cost is sometimes considered together with the transformeras a single unit. Regardless, the transmission, transformer, and feeder costs can be estimated

fairly accurately for planning purposes.Cost of land is another matter entirely. Site and easements or ROW into a site have a

cost that is a function of local land prices, which vary greatly, depending on location andreal-estate markets. Site preparation includes the cost of preparing the site (grading,grounding mat, foundations , buried ductwork, control bu ilding, lighting , fence, landscaping,and access road).

Substation costs vary greatly depending on type, capacity, local land prices, and other

variable circumstances. In rural settings where load density is quite low and minimalcapacity is required, a substation m ay involve a site of only several thousand square feet of

fenced area, a single incoming transmission line (69 kV), one 5 MVA transformer, fusingfor all fault protection, and all "buswork" built with wood poles and conductor, for a total

cost of perhaps no more than $90,000. The substation would be applied to serve a load ofperhaps 4 MW, for a cost of $23/kW. This substation in conjunction with the system aroundit would probably provide service with about ten hours of service interruptions per yearunder average conditions.

How ever, a typical substation built in most suburban and u rban settings w ould be fed bytwo incoming 138 kV lines feeding two 40 MVA, 138 kV to 12.47 kV transformers, each

feeding a separate low side (12.41 kV) bus, each bus with four outgoing distribution feedersof 9 MVA peak capacity, and a total cost of perhaps $2,000,000. Such a substation's cost

could vary from between about $1.5 million and $6 million, depending on land costs, laborcosts, the utility equipment and installation standards, and other special circumstances. In

most traditional vertically integrated, publicly regulated electric utilities, this substationwould have been used to serve a peak load of about 60 MVA (75% utilization of capacity),which at its nomina l $2,000,000 cost works out to $33/kW. In a competitive industry, withtighter design margins and proper engineering measures taken beforehand, this could bepushed to a peak loading of 80 MVA (100% utilization, $25/kW). This substation and the

system around it would probably provide service with about two to three hours of serviceinterruptions per year under average conditions.

Feeder System Costs

The feeder system consists of all the primary distribution lines, includ ing three-phase trunksand their lateral extensions. These lines operate at the primary distribution voltage - 23.9

kV, 13.8 kV, 12.47 kV, 4.16 kV or whatever - and may be three-, two-, or single-phaseconstruction as required. Typically, the feeder system is also considered to include voltageregulators, capacitors, voltage boosters, sectionalizers, switches, cutouts, fuses, any intertie





transformers (required to connect feeders of different voltage at tie points, as, for example,23.9 and 12.47 kV) that are installed on the feeders (i.e., not at the substations or atcustomer facilities).

As a rule of thumb, construction of three-phase overhead, wooden pole crossarm type

feeders of normal, large conductor (about 600 MCM per phase) at a medium distributionprimary voltage (e.g., 12.47 kV) costs about $150,000/mile. However, cost can vary greatlydue to variations in labor, filing and permit costs among utilities, as well as differences indesign standards and terrain. Where a thick base of topsoil is present, a pole can be installedby simply auguring a hole for the pole. In areas where there is rock close under the surface,holes have to be jack-hammered or blasted, and cost goes up accordingly. It is generallyless expensive to build feeders in rural areas than in suburban or urban areas. Thus, while$150,000 is a good average cost, a mile of new feeder construction could cost as little as$55,000 in some situations and as much as $500,000 in others.

A typica l distribution feeder (three-phase, 12.47 kV, 600 MCM/phase) would be rated at

a thermal (maximum) capacity of about 15 MVA and a recommended economic (design)peak loading of about 8.5 MVA peak, depending on losses and other costs. At$150,000/mile, this capacity rating gives somewhere between $10 to $15 per kW-mile asthe cost for basic distribution line. Underground construction of three-phase primary ismore expensive, requiring buried ductwork and cable, and usually works out to a range of$30 to $50 per kW-mile.

Lateral lines - short primary-voltage lines working off the main three-phase circuit - are

often single- or two-phase and consequently have lower costs but lower capacities.Generally, they are about $5 to $15 per kW-mile overhead, with underground costs of

between $5 to $15 per kW-mile (direct buried) to $30 to $100 per kW-mile (ducted).Cost of other distribution equipment, including regulators, capacitor banks and their

switches, sectionalizers, line switches, etc., varies greatly depending on the specifics of eachapplication. In general, the cost of the distribution system will vary from between $10 and$30 per kW-mile.

Service Level Costs

The service, or secondary, system consists of the service transformers that convert primary

to utilization voltage, the secondary circuits that operate at utilization voltage, and theservice drops that feed power directly to each customer. Without exception these are verylocal facilities, meant to move power no more than a few hundred feet at the very most anddeliver it to the customer "ready to use."

Many electric utilities develop cost estimates for this equipment on a per-customerbasis. A typical service configuration might involve a 50 MV A pole-mounted servicetransformer feeding ten homes, as shown in Figure 1.8. Costs for this equipment mightinclude:

Heavier pole & hardware for transformer application $250

50 kW transformer, mounting equipment, and installation $750

500 feet secondary (120/240 volt) single-phase @ $2/ft. $1,000

10 service drops including installation at $100 $1,000

$3,000

This results in a cost of about $300 per customer, or about $60/kW of coincident load.




24 Chapter 1

lateral (primary) secondary

customer service transformer

Figure 1.8 Here, a service transformer, fed from a distribution primary-voltage lateral, feeds in turn

ten homes through secondary circuit operating at utilization voltage.

Maintenance and Operating Costs

Once put into service, T&D equipment must be maintained in sound, operating function,hopefully in the manner intended and recommended by the manufacturer. This will requireperiodic inspection and service, and may require repair due to damage from storms or othercontingencies. In addition, many utilities must pay taxes or fees for equipment (T&D

facilities are like any other business property). Operating, maintenance, and taxes are acontinuing annual expense.

It is very difficult to give any generalization of O&M&T costs, partly because they vary

so greatly from one utility to another, but mostly because utilities account for and reportthem in very different ways. Frankly, the author has never been able to gather a largenumber of comparable data sets from which to produce even a qualitative estimate ofaverage O&M&T costs.

8 With that caveat, a general rule of thumb: O&M&T costs for apower delivery system probably run between 1/8 and 1/30 of the capital cost, annually.

TheCost

toUpgrade Exceeds

theCost

toBuild

One of the fundam ental factors affecting design of T&D systems is that it costs more per

kilowatt to upgrade equipment to a higher capacity than to build to that capacity in theoriginal construction. For example, a 12.47 kV overhead, three-phase feeder with a 9 MWcapacity (336 MCM phase conductor) might cost $120,000/mile to build ($13.33 per kW-mile). Building it with 600 MCM conductor instead, for a capacity of 15 M VA , would costin the neighborhood of $150,000 ($10/kW-mile).

However, upgrading an existing 336 MCM, 9 MW capacity line to 600 MCM, 15 MVA

capacity could cost $200,000/mile - over $30 per kW-mile for the 6 MW of additional

capacity. This is more expensive because it entails removing the old conductor and

8For example, some utilities include part of O&M expenses in overhead costs; others do not. A few

report all repairs (including storm damage) as part of O&M; others accumulate major repair workseparately. Still others report certain parts of routine service (periodic rebuilding of breakers) as a

type of capital cost because it extends equipment life or augments capacity; others report all such

work as O&M, even when the rebuilding upgrades capacity or voltage class.





installing new conductor along with brackets, crossarms, and other hardware required tosupport the heavier new conductor. Typically, this work is done hot (i.e., with the feederenergized), which means the work must be undertaken w ith extreme care and following anumber of safety-related restrictions on equipment and labor.

Thus, T& D planners have an incentive to look at their long-term needs carefully and to"overbuild" against initial requirements if growth trends show eventual demand will be

higher. The cost of doing so must be weighed against long-term savings, but often T& Dfacilities are built with considerable margin (50%) above existing load to allow for futureload growth.

The very high cost per kW for upgrading a T&D system in place creates one of the best

perceived opportunities for DSM and DG reduction. N ote that the capital cost/kW for theupgrade capacity in the example above ($33/kW) is nearly three times the cost of similarnew capacity. Thus, planners often look at areas of the system where slow, continuing loadgrowth has increased load to the point that local delivery facilities are considerably taxed asareas where DSM and DG can deliver significant savings.

In some cases, distributed resources can reduce or defer significantly the need for T&Dupgrades of the type described above. However, this does not assure a significant savings,for the situation is more complicated than an analysis of capital costs to upgrade mayindicate. If the existing system (e.g., the 9 MW feeder) needs to be upgraded, then it is

without a doubt highly loaded, which means its losses may be high, even off-peak. Theupgrade to a 600 MCM conductor will cut losses 8,760 hours per year. Losses cost may

drop by a significant amount, enough in many cases to justify the cost of the upgrade alone.

The higher the annual load factor in an area, the more likely this is to occur, but it is often

the case even when load factor is only 40%. However, DSM and in some cases DG alsolower losses, making the comparison quite involved, as will be discussed later in this book.

Electrical Losses Costs

Movement of power through any electrical device, be it a conductor, transformer, regulator,or whatever, incurs a certain amount of electrical loss due to the impedance (resistance tothe flow of electricity) of the device. These losses are a result of inviolable laws of nature.They can be measured, assessed, and minimized through proper engineering, but nevereliminated completely.

Losses are an ope rating cost

Although losses do create a cost (sometimes a considerable one) it is not always desirable to

reduce them as m uch as possible. Perhaps the best way to put them in proper perspective isto think of T&D equipment as powered by electricity - the system that moves power from

one location to another runs on electric energy itself. Seen in this light, losses are revealed

as what they are — a necessary operating expense to be controlled and balanced againstother costs.

Consider a municipal water department, which uses electric energy to power the pumpsthat drive the water through the pipes to its customers. Electricity is an acknowledgedoperating cost, one accounted for in planning and weighed carefully in designing the systemand estimating its costs. The water department could choose to buy highly efficient pumpmotors, ones that command a premium price over standard designs but provide a savings inreduced electric power costs, and to use piping that is coated with a friction-reducing liningto promote rapid flow of water (thus carrying more water with less pump power), all towardreducing its electric energy cost. Alternatively, after weighing the cost of this premium




26 Chapter 1

equipment against the energy cost savings it provides, the water department may decide touse inexpensive m otors and piping and simply pay more over the long run. The point is thatthe electric power required to move the water is viewed merely as one more cost that had to

be included in determining what is the lowest "overall" cost.

It is the same for power - takes power to move power. Since electric delivery equipmentis powered by its own delivery product, this point often is lost and losses are viewedentirely as a negative factor - a failure on the part of the system and its planners. However,losses are the energy required to power the system in its operation, and therefore just one

other factor to be engineered among many other factors, and their costs, that can be tradedagainst one another in the optimization of its design. In order to do its job of deliveringelectricity, a T&D system must be provided with power itself, just like the waterdistribution system. Energy must be expended to move the product. Thus, a transformerconsumes a small portion of the power fed into it. In order to move power 50 miles, a 138kV transmission line similarly consumes a small part of the power given to it.

Initial cost of equipment can always be traded against long-term losses costs. Highlyefficient transformers can be purchased to use considerably less power to perform theirfunction than standard designs. Larger conductors can be used in any transmission ordistribution line, which will lower impedance and thus losses for any level of powerdelivery. But both exam ples here cost more money initially - the efficient transformer may

cost three times what a standard design does; the larger conductor might entail a need for

not only large wire, but heavier hardware to hold it in place and stronger towers and polesto keep it in the air. In addition, these changes may produce other costs - for example, use

of larger conductor not only lowers losses, but a higher fault duty (short circuit current),

which increases the required rating and cost for circuit breakers. Regardless, initialequipment costs can be balanced against long-term losses costs through careful study ofneeds, performance, and costs to establish a minim um overall (present worth) cost.

Load-related losses

Flow of electric power through any device is accompanied by what are called load-related

losses, which increase as the power flow (load) increases. These are due to the impedanceof the conductor or device. Losses increase as the square of the load - doubling the powerflowing through a device quadruples the losses. Tripling power flow increases the losses by

nine.With very few exceptions, larger electrical equipment always has a lower impedance,

and thus lower load-related losses, for any given level of power delivery. Hence, if thelosses inherent in delivering 5 MW using 600 MCM conductor are unacceptably large, the

use of 900 MCM conductor will reduce them considerably. The cost of the larger conductorcan be weighed against the savings in reduced losses to decide if it is a sound economicdecision.

No-load losses

"Wound" T&D equipment - transformers and regulators - have load-related losses as dotransmission lines and feeders. But they also have a type of electrical loss that is constant,not a function of loading. No-load losses constitute the electric power required to establish amagnetic field inside these units, without which they would not function. Regardless ofwhether a transformer has any load - any power passing through it at all - it will consume a

small amount of power, generally less than 1 % of its rated full power, simply because it isenergized and "ready to work." N o-load losses are constant, 8,760 hours per year.





Given similar designs, a transformer will have no-load losses proportional to its capacity

- a 10 MVA substation transformer will have twice the no-load losses of a 5 M V Atransformer of similar voltage class and design type. Therefore, unlike the situation with aconductor, selection of a larger transformer does not always reduce losses, because while

the larger transformer will always have lower load-related losses, it will have higher no-load losses.

Again, low-loss transformers are available, but cost more than standard types. Lower-

cost-than-standard, but higher-loss, transformers are also available, and often are a goodinvestment for back-up and non-continuous use applications.

The costs of losses

The electric power required to operate the T&D system - the electrical losses — is typically

viewed as having two costs, demand and energy. Demand cost is the cost of providing the

peak capacity to generate and deliver power to the T&D equipment. A T&D system thatdelivers 1,250 MW at peak might have losses during this peak of 100 MW. This means the

utility must have generation, or buy power at peak, to satisfy this demand, whose cost iscalculated using the utility's power production cost at time of peak load. This is usually

considerably above its average power production cost.

Demand cost also ought to include a considerable T&D portion of expense. Every

service transformer in the system (and there are many) is consuming a small amount ofpower in doing its job at peak. Cumulatively, this might equal 25 MW of power - up to 1/4

of all losses in the system. That power must not only be generated by the utility buttransmitted over its transmission system, through its substations, and along its feeders to

reach the service transformers. Similarly, the power for electrical losses in the secondary

and service drops (while small, these are numerous and low voltage, so that their

cumulative contribution to losses is noticeable) has to be moved even farther, through the

service transformers and down to the secondary level.

Demand cost of losses is the total cost of the capacity to provide the losses and movethem to their points of consumption. Losses occur whenever the power system is in

operation, which generally means 8,760 hours per year. While losses vary as the square of

load, so they drop by a considerable margin off-peak. Their steady requirement every hour

of the year imposes a considerable energy demand over the course of a year. This cost is the

cost of the energy to power the losses. Example: Consider a typical 12.47 kV, three-phase,OH feeder, with 15 MW capacity (600 MCM phase conductor), serving a load of 10 MW at

peak with 4.5% primary-level losses at peak (450 kW losses at peak), and having a load

factor of 64% annually. Given a levelized capacity cost of power delivered to the low side

bus of a substation of $10/kW, the demand cost of these losses is $4,500/year. Annualenergy cost, at 3.50 /kWh, can be estimated as:

450 kW losses at peak x 8,760 hours x (64% load factor)2

x 3.50 = $56,500

Thus, the losses' costs (demand plus energy costs) for this feeder are nearly $60,000

annually. At a present worth discount factor of around 11%, this means losses have anestimated present worth of about $500,000. This computation used a simplification -

squaring the load factor to estimate load factor impact on losses - which tends to

underestimate losses' costs slightly. Actual losses costs probably would be more in the

neighborhood of $565,000 PW. If the peak load on this feeder were run up to its maximum

rating (about 15 MW instead of 10 MW) with a similar load factor of 64%, annual losses

cost would increase to (15/10)2 or$1,250,000 dollars. This roughly two-to-one cost ratio is




28 Chapter 1

Figure 1.9 Cost of power delivery varies depending on location. Shown here are the annual capacitycosts of delivery evaluated on a ten-acre basis throughout a coastal city of population 250,000. Costvaries from a low of $85/kW to a high of $270/kW.

common for feeders in many utility systems, which are: (1) designed with a considerable

margin between expected peak load and their actual thermal (maximum continuous)capacity, for reasons of reliability margin (so that there is capacity to pick up customers on

a nearby feeder should it go out of service), and (2) made large for economics reasons -

usually losses are too expensive at close to the thermal limit of any conductor. This typical

feeder would include perhaps four miles of primary trunk at $150,000/mile and thirty miles

of laterals at $50,000/mile, for a total capital cost of about $2,100,000. Thus, total losses

costs are on the order of magnitude of original cost of the feeder itself, and in cases where

loading is high can approach that cost. Similar loss-capital relations exist for all other levels

of the T&D system.

Total of T&D Costs

Table 1.4 shows the cost of providing service to a "typical" residential customer in an

example power system. These figures are representativeof all systems, but costs, practices,

and accounting systems vary so that these are not general values applicable to all utilities.

Table 1.4 Cost of Providing Service to a TypicalResidential Customer

Level

TransmissionSubstationFeederService

AllAll

Cost Components

4 kW x 100 miles x $.75/kW mile4kWx$60 /kW4 kW x 1.5 miles x $10/kW-milel/10th of 50 kVA local service system

Total Initial cost (Capital)

Operations, Maintenance, and Taxes (PW next 30 years)Cost of electrical losses (PW next 30 years)

Cost

$300$240$60

$300

$900

$500$700

Estimated cost of power delivery, 30 years, PW $2,100





1.8TYPES OF DISTRIBUTION SYSTEM DESIGN

There are three fundamentally different ways to lay out a power distribution system used by

electric utilities, each of which has variations in its own design. As shown in Figure 1.10,

radial, loop, and network systems differ in how the distribution feeders are arranged and

interconnected about a substation.

Radial Feeder Systems

Most power distribution systems are designed to be radial, to have only one path between

each customer and the substation. The power flows exclusively away from the substation

and out to the customer along a single path, which, if interrupted, results in complete loss of

power to the customer. Radial design is by far the most widely used form of distribution

design, accounting for over ninety-nine percent of all distribution construction in North

America. Its predominance is due to two overwhelming advantages: it is much less costly

than the other two alternatives and it is much simpler in planning, design, and operation.

In most radial plans, both the feeder and the secondary systems are designed and

operated radially. Each radial feeder serves a definite service area (all customers in that area

are provided power by only that feeder). Many radial feeder systems are laid out and

constructed as networks, but operated radially by opening switches at certain points

throughout the physical network configuration (shown earlier in Figure 1.6), so that the

resulting configuration is electrically radial. The planner determines the layout of the

network and the size of each feeder segment in that network and decides where the open

points should be for proper operation as a set of radial feeders.

A further attribute of many radial feeder system designs, although not essential, is the

use of single-phase laterals. Throughout North America, most utilities use single- and two-phase laterals to deliver small amounts of power over short distances, rather than use all

three phases. These laterals are also radial, but seldom, if ever, end in a switch (they just

end). There are some utilities, particularly urban systems in Europe, Africa, and Asia, that

build every part of the radial distribution system, including laterals, with all three phases.

Each service transformer in these systems feeds power into a small radial system around

it, basically a single electrical path from each service transformer to the customers nearby.

Regardless of whether it uses single-phase laterals or not, the biggest advantages of the

radial system configuration, in addition to its lower cost, is the simplicity of analysis and

Radial Loop Network

Figure 1.10 Simplified illustration of the concepts behind three types of power distribution

configuration. Radial systems have only one electrical path from the substation to the customer, loop

systems have two, and networks have several. Arrows show most likely direction of electric flows.




30 Chapter 1

predictability of performance. Because there is only one path between each customer andthe substation, the direction of power flow is absolutely certain. Equally important, the loadon any element of the system can be determined in the most straightforward manner - by

simply adding up all the customer loads "downstream" from that piece of equipment.

Before the advent of economical and widely available computer analysis, this alone wasan overwhelming advantage, for it allowed simple, straightforward, "back of the envelope"

design procedures to be applied to the distribution system with confidence that the resultingsystem would work w ell. The simplicity of analysis and confidence tha t operating behavioris strictly predictable are still great advantages.

Because load and power flow direction are easy to establish, voltage profiles can bedetermined with a good degree of accuracy without resorting to exotic calculation methods;equipment capacity requirements can be ascertained exactly; fault levels can be predictedwith a reasonable degree of accuracy; and protective devices - breaker-relays and fuses -

can be coordinated in an absolutely assured manner, w ithou t resorting to network methodsof analysis. Regulators and capacitors can be sized, located, and set using relatively simpleprocedures (simple compared to those required for similar applications to non-radialdesigns, in which the power flow direction is not a given).

On the debit side, radial feeder systems are less reliable than loop or network systemsbecause there is only one path between the substation and the customer. Thus, if any

element along this path fails, a loss of power delivery results. Generally, when such afailure occurs, a repair crew is dispatched to re-switch temporarily the radial patternnetwork, transferring the interrupted customers onto another feeder, until the damagedelement can be repaired. This minimizes the period of outage, but an outage still occurred

because of the failure.Despite th is apparent flaw, radial distribu tion systems, if well designed and constructed,

generally provide very high levels of reliability. For all but the most densely populatedareas, or absolutely critical loads (hospitals, important municipal facilities, the utility's owncontrol center) the additional cost of an inherently more reliable configuration (loop ornetwork) cannot possibly be justified for the slight improvement that is gained over a well-designed radial system.

Loop Feeder Systems

An alternative to purely radial feeder design is a loop system, which has two paths betweenthe power sources (substations, service transformers) and each customer. Such systems areoften called "European" because this configuration is the preferred design of manyEuropean utilities. Equipment is sized and each loop is designed so that service can bemaintained regardless of where an open point might be on the loop. Because of thisrequirement, whether operated radially (with one open point in each loop) or with closedloops, the basic equipment capacity requirements of the loop feeder design do not change.

Some urban areas in Europe and Asia are fed by multiple hierarchical loop systems: a100+ kV sub-transmission loop routes power to several substations, out of which severalloop feeders distribute power to service transformers, which each route powers through a

long loop secondary.In terms of complexity, a loop feeder system is only slightly more complicated than a

radial system - power usually flows out from both sides toward the middle, and in all casescan take only one of two routes. Voltage drop, sizing, and protection engineering are onlyslightly more complicated than for radial systems.

But if designed thus, and if the protection (relay-breakers and sectionalizers) is also builtto proper design standards, the loop system is more reliable than radial systems. Service





will not be interrupted to the majority of customers whenever a segment is outaged, because

there is no "downstream" portion of any loop.

The major disadvantage of loop systems is a higher capacity cost than purely radial

distribution. A loop must be designed to meet all power and voltage drop requirements

when fed from either end. It needs extra capacity on each end, and the conductor must belarge enough to handle the power and voltage drop needs of the entire feeder if fed from

either end. This makes the loop system inherently more reliable than a radial system, but the

larger conductor and extra capacity increase its cost.

Distribution Networks

Distribution networks are the most complicated, most reliable, and in very rare cases also

the most economical method of distributing electric power. A network involves multiple

paths between all points in the network. Networks provide continuity of service (reliability)

far beyond that of radial and loop designs: if a failure occurs in one line, power instantly

and automatically re-routes itself through other pathways.

Most distribution networks are underground systems, simply because they are employed

mostly in high density areas, where overhead space is not available. Rarely is the primary

voltage level a network, because that proves very expensive and often will not work well.9

Instead, a "distribution network" almost always involves "interlaced" radial feeders and a

network secondary system - a grid of electrically strong (i.e., larger than needed to just feed

customers in the immediate area when everything is functioning) conductor connecting all

the customers together at utilization voltage. In this type of design, the secondary grid is fed

from radial feeders through service transformers, basically the same way secondary is fed in

radial or loop systems. The feeders are radial, but laid out in an interlaced manner - nonehas a sole service area, but instead they overlap, two or more feeding alternate transformers

into a secondary network, as shown in Figure 1.11. While segments from two feeders

always run parallel in any part of the system, the same two feeders never overlap for all of

their routing. The essence of the interlaced system (and a design difficulty in any practical

plan) is to mix up feeders so that each feeder partially parallels quite a few other feeders.

Thus, if it fails, it spreads its load over quite a few other feeders (Figure 1.12).

At a minimum, distribution networks use an interlacing factor of two, meaning that two

feeders overlap in any one region, each feeding every other service transformer. But such a

system will fail when any two feeders are out of service. Interlacing factors as high as five

(five overlapping feeders, each feeding every fifth consecutive service transformer) have

been built. Such systems can tolerate the loss of any three feeders (the other two in any area

picking up the remaining load, although often very overloaded) without any interruption of

customer service. If an element fails, the power flow in the elements around it merely re-

distributes itself slightly. So slightly, in fact, that a real problem can be determining when

failures occur. If the damage is not visible (most networks are underground systems) and no

alarm or signal is given by monitoring equipment, the utility may not know a failure

occurred until months later, when a second failure nearby puts a strain on the system or

causes an outage.

Networks are more expensive than radial distribution systems, but not greatly so indense urban applications, where the load density is very high, where the distribution must

be placed underground, and where repairs and maintenance are difficult because of traffic

9Particularly if a feeder network is created by networking feeders out of different substations, this

puts feeder paths in parallel with transmission between substations, which often results inunacceptable loop and circular flows and large dynamic shifts in load on the distribution system.




32 Chapter 1

service transforme rs

Feeder A

Feeder B

Figure 1.11 To obtain an interlacing factor of 2, two feeders are routed down each street, withalternating network transformers fed from each.

and congestion, networks may cost little more than loop systems. N etworks require littlemore conductor capacity than a loop system. The loop configuration required "double

capacity" everywhere to provide increased reliability. A distribution network is generallyno worse and often needs considerably less capacity and cost, if it is built to a clever designand its required capacity margins are minimized.

N etworks have one major disadvantage. They are much more complicated than otherforms of distribution, and thus much more difficult to analyze and operate. There is no"downstream" side to each unit of equipment in a network or loop system. This complicatesload estimation, power flow analysis, and protection planning. It makes maintenance and

restoration more difficult in many cases. Loadings, power flow, and fault current andprotection must be determined by network techniques such as those used by transmission

planners.

NORMAL

• • • •

FEEDER #2 FAILED

NORMAL FEEDER #2 FAILED

Figure 1.12 Top, a non-interlaced feeder system experiences the loss of one feeder, and all

transformers in the lower right part of the system are lost - service is certain to be interrupted. Bottom,

the same system, but interlaced. Loss of the feeder is a serious contingency, but can be withstoodbecause the feeder losses are distributed in such a way that each transformer out of service issurrounded by transformers still in service.





However, more involved calculation methods than those applied to transmission may be

required, because a large distribution network can consist of 50,000 nodes or more - the

size of the very largest transmission-level power pool. Distribution network load flows areoften more difficult to solve than transmission systems because the range of impedances in

the modeled circuits is an order of magnitude wider.In densely populated regions, such as the center of a large metropolitan area, networks

are not inherently more expensive than radial systems designed to serve the same loads.

Such concentrated load densities require a very large number of circuits anyway, so that

their arrangement in a network does not inherently increase the number of feeder andsecondary circuits, or their capacity requirements. It increases only the complexity of thedesign. But in other areas, such as in most cities and towns, and in all rural areas, a network

configuration will call for some increase (in kVA-feet of installed conductor) over that

required for a radial or loop design. The excess capacity cost has to be justifiable on thebasis of reliability.

Networks and types of network designs are discussed further in Chapter 19, section 6.

Large-Trunk vs. Multi-Branch Feeder Layout

Most distribution systems are radial, and that approach is most appropriate for the vast

majority of situations. For that reason this book focuses primarily on radial system design.

Figure 1.13 illustrates two different ways to lay out a radial distribution system, and

illustrates a basic concept of distribution planning: flexibility of design. Each of the two

configurations can be engineered to work in nearly any situation. Each has advantages anddisadvantages in some situations as compared to the other, but neither is always superior tothe other in terms of reliability, cost, ease of protection, and service quality in all situations.

Most planning engineers have a preference for one or the other - in fact, about 20% of

utilities have standardized on the large-trunk design as their recommended guideline while

another 20% prefer the multi-branch approach. Beyond showing that there are significantly

different ways to lay out a distribution system, this brings to light an important point about

distribution design: major differences in standards exist among electric utilities; as a resultcomparison of statistics or practice from one to the other is often not completely valid.

These concepts and practices are discussed in greater detail in Chapters 13 and 14.

r™: i' T, 1

' 1 1

i nf i l li i i J

[ i n

t i nr [ i r1 1 1 1 J

[ I I I

[ I I[ I f1 1 1

[ I I

D-

Figure 1.13 Two ways to route a radial feeder to 108 service transformers. Left, a "multi-branch"

configuration. Right, a "large trunk" design. Either approach can always be made to do the job.

N either is a lower-cost or greater-reliability design under all conditions, although many utilitiesstandardize or institutionalize practices around only one approach, thus losing some flexibility of

approach in minimizing costs and improving reliability.












34 Chapter 1

Ten Miles

Figure 1.14 A power system is divided by substation service boundaries into a set of substationservice areas, as shown.

Substation and Feeder Service Areas

As mentioned earlier, in most power systems, each substation is usually the sole provider ofelectrical service to the region around it - its service area. Similarly, feeders and

distribution networks also have distinct service areas. Usually, the service area for a

substation, feeder, or other unit of equipment is the immediate area surrounding it, andusually these service areas are contiguous (i.e. not broken into several parts) and exclusive -

no other similar distribution unit serves any of the load in an area. An example, Figure 1.14

shows a map of substation service areas for a rectangular portion of a power system. Eachdistribution substation exclusively serves all customers in the area containing it.

Cumulatively, the customers in a substation's or feeder's service territory determine itsload, and their simultaneous peak demand defines the maximum power the substation mustserve. Within a power system, each individual part, such as a substation or servicetransformer, will see its peak load at whatever time and in whatever season the customers in

its service area generate their cumulative peak demand. One result of this is that the peakloads for different substations often occur at different seasons of the year or hours of the

day. But whenever the peak occurs, it defines the maximum power the unit is required todeliver. Peak demand is one of the most important criteria in designing and planningdistribution systems. Usually it defines the required equipment capacity.

Dynamic Service Area Planning

By making switching changes in the distribution system, it is possible to expand or shrink a

substation or feeder's service area significantly, increasing or decreasing its net load, orkeeping is loading constant over time as the demand in a region gradually grows. Switching

to "balance loading" is an important element of T&D planning, as illustrated in Figure 1.15,which shows a very typical T&D expansion situation. Two neighboring substations, A andB, each have a peak load near the upper limit of their reliable load-handling range. Load isgrowing slowly throughout the system, so that in each substation annual peak load is

increasing at about 1 MW per year. Under present conditions, both will need to be upgradedsoon. Approved transform er types, required to add capacity to each, are available only in 25MVA or larger increments, costing $500,000 or more.





Before After

transferred load

Figure 1.15 Load in both substations is growing at about 1 MW per year. Each substation has

sufficient capacity to handle present load within contingency criteria (a 25% margin above peak) but

nothing more. By transferring load as shown, only one substation has to be reinforced with anadditional (25 MVA ) capacity, yet both end up with sufficient margin for another ten years' growth.

Service area shifts like this are how expansion costs are kept down in spite of the fact that equipment

like transformers is available only in large, discrete sizes.

Both substations do not need to be reinforced. A new 25 MVA transformer andassociated equipment are added to substation A, increasing its ability to handle a peak load

by about 20 MVA. Ten MW of substation B's service area is then transferred to A. The

result is that each substation has 10 MW of margin for continued load growth - further

additions are not needed for 10 years.

This type of planned variation in service areas is a major tool used to keep T&D

expansion costs low, a key element in building a reliable, economical schedule of

expansion. Optimization of this particular aspect of planning can be a challenge, not

because of any inherent difficulty in analysis, but simply because there are so many parts of

the system and constraints to track at one time. This is one reason for the high degree ofcomputerization in distribution planning at many utilities. Balancing the myriad

requirements of many substations and their design and operating constraints is an ideal

problem for numerical optimization techniques.

1.9 THE SYSTEMS APPROACH AND TWO-Q PLANNING

One complication in determining the most economical equipment for a power system is that

its various levels — transmission, substation, and distribution - are interconnected, with the

distribution, in turn, connected to the customers. This means that the best size and

equipment type at each level and location in the system is a function not only of the localload, but of the types of equipment selected for the other levels of the system nearby, theirlocations and characteristics, as well as the loads they serve. Thus, in general, T&D

equipment is so interconnected that it is impossible to evaluate any one aspect of a system's

design without taking many others into account.

For example, consider the question of substation spacing - determining how far apart

substations should be, on average, for best utilization and economy. Within any utility

system, if substations are located farther apart, there will be fewer of them, reducing the




36 Chapter 1

cost of buyin g and prep aring substation sites, as w ell as reducing the cost of building such alarge num ber of substations. H owever, with fewer substations, each substation mu st serve alarger area of the system and will have a larger load, and thus require a larger capacity,meaning it must have more or larger transformers. Overall, this does tend to reduce the

overall cost of the substation level, because there is an economy of scale to substations: one100 MVA site is less costly than two 50 MV A sties, etc.

But tha t is not the end of the cost cons iderations; the aforementioned interrelationshipsmean transm ission impacts m ust be considered. Larger substations w ill also require a largeramount of power to be brought to each one, which generally calls for a higher sub-transmission voltage. Yet, there will be fewer sub-transmission lines required (becausethere are fewer substations to which power must be delivered). All these aspects of layoutare related - greater substation spac ing calls for larger substations with bigger transformers,and a higher transmission v oltage, but fewer lines are needed - and all together can create

better economies of scale if spacing is "optimized."

Furthermore, there is yet another set of interrelated impacts on the downstream side ofthe substation. The feeder system is required to distribute each substation's power throughits service area, moving power out to the boundary between each substation's service areaand that of its neighbors. Moving substations farther apart means that the distributionsystem must move power, on average, a greater distance. Distributing power over theselonger distances requires longer and more heavily loaded feeders. This in turn increasesvoltage drop and can produce higher losses, all of which can increase cost considerably.Employing a higher distribution voltage (such as 23.9 kV instead of 13.8 kV) improvesperformance and economy, bu t regardless it costs more to distribute pow er from a few large

substations than from many smaller substations which will be closer together.The major point: All of these aspects of system design are interconnected: (1) substation

spacing in the system, (2) size and number of substations, (3) sub-transmission voltage anddesign, and (4) distribution feeder voltage and design. One of these factors cannot be

optimized without close evaluation of its interrelationship with the others. Therefore,determining the most cost-effective design involves evaluating the transmission-substation-feeder system design as a whole against the load pattern, and selecting the best combinationof transmission voltage, substation transformer sizes, substation spacing, and feeder systemvoltage and layout. This economic equipment sizing and layout determination is based on

achieving a balance between two conflicting cost relationships:Higher voltage equipment is nearly alw ays more economical on a per-MW basis.

Higher voltage equipment is available only in large sizes (lots of MW).

In cases where the local area demands are modest, higher voltage equipment may be

more expensive simply because the minimum size is far above what is required - the utility

has to buy more than it needs. How these two cost relationships play against one anotherdepends on the load, the distances over which power must be delivered, and other factorsunique to each power system, such as the voltages at which power is delivered from the

regional power pool and whether the system is underground or overhead.Figure 1.16 illustrates the difference that careful coordination of system design between

levels of the power system can have in lowering overall cost. Shown are the overall costsfrom various combinations of T&D system layout for a large metropolitan utility in theeastern United States. Each line connects a set of cost com putations for a system built with

the same transmission and distribution voltages (e.g., 161 kV transmission and 13.8 kV

distribution) but varying in substa tion sizes (and hence, imp licitly, their spacing).





In all cases, the utility had determined it would build each substation with two equally

sized transformers (for reliability), with none over 75 MVA (larger transformers are toodifficult to move along normal roads and streets, even on special trailers). Either 161 kV or69 kV could be used as sub-transmission, either 23.9 kV or 13.8 kV could be used as

distribution voltage. Any size transformer, from 15 MVA to 75 MVA, could be used,meaning the substation could vary from 30 MVA to 150 MVA in size. (Peak load of such

substations can normally be up to 75% of capacity, for a peak load of from 23 to 100 MW.)

Substation spacing itself is implicit and not shown. Given the requirement to cover thesystem, determining transmission voltage, distribution, and substation size defines thesystem design guidelines entirely.

Overall, the ultimate lowest cost T&D system guidelines are to build 120 MVA

substations (two 60 MVA transformers) fed by 161 kV sub-transmission and distributingpower at 23.9 kV. This has a levelized cost (as computed for this utility) of about $179/kW.

(Levelized and other time-versus-money concepts will be discussed in Chapter 5). In this

particular case, a high distribution voltage is perhaps the most important key to good

economy - if 13.8 kV is used instead of 23.9 kV as the primary voltage, minimumachievable cost rises to $193/kW.

The very worst design choices plotted in Figure 1.16, from an economic standpoint,

would be to build 25 MVA substations fed by 161 kV sub-transmission and feeding power

to 23.9 kV feeders ($292/kW). This would require many small substations, each below theeffective size of both the transmission and distribution voltages used. Overall, 161 kV and

23.9 kV are the correct choices for economy, bu t only if used in conjunction with a few,

large substations. If substations are to be 25 MVA, then 69 kV and 13.8 kV do a much

more economical job ($228/kW), but still don't achieve anything like the optimum value.The most important point: Achieving economy in power delivery involves coordinating the

interactions, performance, and economies of the multiple system levels. Chapters 11-19

cover the issues and techniques of coordinated multi-level planning.

300

V*

O

O

UlQ.

"5

1<0Oo 200

161kV&13.8kV

69kV & 23.9kV

6 9kV&13 .8kVX

50 100

SUBSTATION CAPACITY - MVA

150

Figure 1.16 Overall cost of T&D system depends on the balanced design of the sub-transmission,

substation, and feeder level, as described in the text. Cost can vary by significant margins depending

on how well performance and economy at various levels of the system are coordinated.












38 Chapter 1

Two-Q Planning

Figure 1.16 illustrates rigorously cost-conscious planning and engineering from withinthe traditional utility paradigm of focusing on capacity and assessing options on the basisof cost per kW served or cost per kVA of capacity. A complication of modern, non-

traditional distribution planning is that reliability is often a key design element (seesection 1.3). Planners are challenged to reduce overall cost while achieving designs thatachieve targets fo r both capacity an d reliability. Planning methods an d concepts that dealsimultaneously with a distribution system's quantity (demand an d capacity) and quality

(continuity of sufficient service - reliability)are labeled by the author as Two-Q m ethods.

Traditional distribution planning and engineering was predominately "single-Q."

Reliability was addressed through the use of standards and was not a specific, targetedlevel of performance. Cost was minimized with respect to meeting capacity needs. Themost economical design alternative from the capacity standpoint (as discussed above an d

illustrated in Figure 1.16) may not be the most reliable option, nor the alternative thatoffers the best "bang for the buck" from the standpoint of reliability. (The varioussystems depicted in Figure 1.16 do not all have the same level of reliability.)

In general, due to the layout and behavior of radial distribution systems, lower voltageprimary feeder systems h ave sligh tly better relia bility statistics than higher v oltagesystems, other things being equal. Thus, a 12.5 kV primary distribution system willusually have slightly better reliability than a 25 kV system designed to serve the samearea. A planner choosing betw een those two options w ould need to determine:

if the difference in reliability between these different voltage options is important

and worth any cost differential

if an y savings due to the lower cost of the higher voltage system (assuming that isthe case) can be used to buy reliability improvement equipment such as reclosers

and automation that will improve that option's reliability so that it is equal orsuperior to that offered by the lower-voltage option

The basic concept behind all Two-Q methods is to extend the planning analysis andevaluation, and cost minimization approaches, to cover the additional dimension of

reliability from a performance standpoint. This means they plan and design systems to

numerical reliability targets in addition to, as traditional methods do, planning anddesigning to numerical demand targets. Two-Q methodology does not mean any specificanalytical method, but includes all methods that take this approach.

Figures 1.17-1.19 show the Two-Q equivalent of the "single-Q" analysis shown inFigure 1.16. Two-dimensional analysis produces manifolds (surfaces) in a threedimensional space of cost versus reliability versus capacity, rather than lines on a plane(cost versus capacity). Figure 1.17 shows the results for one system type (69 kV and 13.8kV). Figure 1.18 shows a second type of system (161 and 23.9 kV) added, providing datato assemble Figure 1.19's identification of situations where one or the other is leastcostly. This analysis is the Two-Q equivalent of the traditional cost-minimization system

approach covered in Figure 1.16. W ith regard to Two-Q planning:

Reliability is an issue in planning: Systems built to equivalent engineeringstandards (all of those depicted on the broad lines in Figures 1.17 and 1.18) do notgive the same performance with respect to reliability.

Achieving targeted levels of reliability means designing to constant reliabilitytargets, not constant design standards.





Figure 1.17 Surface depicting the costs for a 161 - 13.8 kV system design standard for various

substation capacities and optimized to meet various levels of SAIDI (system average intem pti onduration index ) targets. The broad line represents the same set of systems as the 69+13.8 kV ine inFigure 1.16, standardized designs in which substation size varies. As shown these various options

are not of constant reliability level, but vary from near 100 minutes to about 165 minutes SAIDI

annually, with larger substation systems having worse reliability.

Figure 1.18 A second surface, depicting the costs for the 138 - 23.9 kV system design standard for

various substation capacities and optimized to meet various levels of SAD1 (system averageinterruption duration index) targets. The most lightly shaded surface area shows the portion of the

138-23.9 kV surface that has higher costs than 69-13.8 kV designs.




40 Chapter 1

0 50 100 150

SUBSTATION CAPACITY - MVA

Figure 1.19 Projection of the lowest cost areas of the two surfaces leads to this information,(heavily shaded area) depicting situations where the 69-13.8 kV design paradigm is less costly thanthe 161-23.9 kV one.

Planning that includes reliability is considerably more complicated than traditionalplanning that minimizes cost/kW.

Reliability can be managed in company with cost and traditional design goals.

Two-Q types of techniques are becoming standard in the power industry, as more and

more utility commissions regulate utility performance with respect to both profit andcustomer service quality. Various procedures and analytical methods exist to address

reliability and produce the types of information shown in Figures 1.17 through 1.19. These

will be discussed in much more detail in Chapters 23 and 28 .Are Two-Q Methods Reliability Improvementor Cost-Reduction Techniques?

For the most part, Two-Q methods can be viewed as cost reduction methods for modern

electric delivery utilities, rather than as reliability improvement methods. Traditional

electric distribution planning methods and practices achieved largely satisfactory levels ofcustomer service reliability through the use of design, equipment, and operating standards.

Adherence to these standards was expected to provide "good reliability," and in the vast

majority of cases it did. But use of rigid standards was not always optimal from a cost

standpoint. Standards would sometimes lead to facilities that were "overbuilt" from thestandpoint of reliability, and often a standard would call for more expense than minimally

necessary. By contrast, Two-Q eschews rigid standards for equipment and design, in favorof rigid numerical standards (quantitative targets) for reliability. This requires more

complicated analysis and planning methods, but usually leads to lower cost designs toachieve the targeted levels of reliability. Two-Q spends less in situations where that cost

reduction will not affect reliability.The majority of applications of Two-Q are for reducing

the cost of achieving satisfactory, and rather traditional, levels of reliability. For this reason

it is perhaps most proper to view Two-Q as predominately a cost reduction methodology.

Two-Q methods can and are also used in situations where reliability must be augmented,either because the traditional design is not working out, or because much better reliability

than traditional levels is needed. In either case, it again minimizes the cost to achieve the

required reliability. Therefore, again, it is a cost-minimizing technique.

Of course, Two-Q, by achieving designs that meet quantitative reliability targets, doeshelp produce more consistent reliability performance and assure targeted levels are more

likely to be reached, so it is also legitimately a way of improving reliability beyond thatgiven by traditional approaches.










1.10 SUMMARY OF KEY POINTS

A transmission and distribution system moves power from a utility's power production andpurchase points to its customers. The T&D system's mission of delivering power to the

customers means that it must be composed of equipment spread throughout the serviceterritory, arranged locally so that capacity is always in proportion to local electrical demand,with the facilities in each neighborhood sized and configured both to fit well into the wholeand to serve the local needs. In the authors' opinion, engineering a system to meet thischallenge is seldom easy, but engineering a system to do so at the min imum possible cost isalways extremely cha llenging.

A T&D system is composed of several interconnected, hierarchical levels, each ofwhich is required for completion of the power delivery task. These levels are:

• transmission

• sub-transmission

• substation

• feeder

• secondary

• customer

To a certain extent, the burden of power delivery, and costs, can be shifted from one

level to another through changes in the specifications of equipment, lay-out standards, anddesign of the various levels. For exam ple, costs can be pared at the substation level by usingfewer, larger substations, but this means feeders in each substation area will have to carrypower farther, and perhaps carry more power per feeder as well, increasing feeder costs.Low overall design cost is achieved by balancing these factors. The performance andeconomy, and thus the design, of a power system are dominated by a number of constraintsdue to physical laws, and further shaped by a number of practical considerations withregard to equipment, layout, and operating requirements. The more important of these arelisted in Table 1.5, and discussed below.

Three Basic Requirements Dominate T&D Planning

The T&D system must cover ground

This is the rule about T&D - ultimately the electric system must "run a wire" to everycustomer. A significant portion of the cost of a distribution system, perhaps 25%, is due tothis requirement alone, independent of the amount of peak load, or energy supplied, orreliability required. Although this requirement does not create the majority of costs, theauthor considers it the single most important aspect of T&D because it is most responsiblefor dictating the character of the system requirements and for shaping the constraints andchallenges facing power delivery planners.

The T&D system must have sufficient capacity to meet peak demand

The T&D system must be designed not to meet average loading conditions, but to handlepeak demand levels, even if those last only a few hours a year. The requirement forcapacity to meet peak demands, above and beyond the minimum levels needed just to"cover ground," is responsible for about 25-40% of the cost of most T&D systems, but

generally does not contribute m uch to design challenges or constraints.




42 Chapter 1

Table 1.5 One-Page Summ ary of Chapter 1

A T&D system must cover ground.

A T&D system must have sufficient capacity to meet peak dem and.

A T&D system must achieve reliability on the order of 99.975% or better.

Six "natural laws" shape the character of T&D system s and their equipment.

1 . It is more economical to move power at high voltage than at low voltage.

2. The higher the voltage, the greater the capacity and the greater the cost ofotherwise sim ilar equipm ent.

3. Utilization voltage is useless for the transmission of power.

4. It is costly to change voltage level.

5. Power is more economical to produce in very large amounts. Claims by theadvocates of modern distributed generators notwithstanding, there is asignificant economy of scale in generation - large generators producepower more economically than small ones. Thus, it is most efficient toproduce power at a few locations utilizing large generators.

6. Pow er must be delivered in relatively small quan tities at low (120 to 250

volts) voltage levels.

A power distribution system consists of multiple "levels": sub-transmission,substation, feeder, and service.

The systems approach - planning and engineering the four levels of the systemas a whole - is a key element of good planning; a power delivery system's partscannot be view ed in isolation, particularly if one desires to truly minimize cost.

Electrical equipment is available only in certain discrete sizes. Planners mustbuild their systems with transformers, breakers, cables, and other "buildingblocks" that are available only in discrete sizes such as 15, 25,40, and 60 MVA .

Dynamic service area re-assignment through switching is a power tool for

maintaining high utilization of facilities while accommodating the fact that only

discrete equipment sizes are available, ultimately reducing cost if used well.The cost per kW to upgrade existing facilities is usually greater than the costper kW to build it initially. Often it makes economic sense to install morecapacity than needed in order to avoid upgrade costs later on.

Peak demands are non-coincident - they do not all occur at the same time.

Electrical losses can create a significant cost, often greater over the lifetime of

the equipm ent than the cost of the equipment and its care, even w hen these long-term losses costs are discounted using valid time-value-of-money methods.

Reliability was traditionally obtained through standards that specifiedcontingency margins and design features.

Reliability is increasingly achieved in modern systems by "designing" to

specific targets using reliability-based engineering methods.





Electrical connectivity must be maintained at very high levels of reliability

Reliability on the order of 99.975% or better - less than two hours out of service per year -

is typically required in most distribution systems built in first- and second-world countries.

This requires protection, sectionalizing, and control equipment, along with redundant

capacity, and operations resources. All told, this requirement for high reliability is

responsible for roughly 50% of the cost of most T&D systems. It is thus the most

important cost element in modern power systems and also creates design and cost-reduction

challenges.

Six Natural Laws of Power Delivery

The physical phenomena and the natural laws that govern their behavior, along with the

realities of power delivery needs, produce six "laws" or fundamental truths that shape T&D

system layout and performance.

1. It is more economical to move power at high voltage. The higher the voltage, thelower the cost per kilowatt to move power any distance.

2. The higher the voltage, the greater the capacity and the greater the cost of

otherwise similar equipment. Thus, high voltage lines, while potentially

economical, cost a great deal more than low voltage lines, but have a much

greater capacity. They are only economical in practice if they can be used to

move a lot of power in one block - they are the giant economy size, but while

always giant, they are only economical if one truly needs the giant size.

3. Utilization voltage is useless for the transmission of power. The 120/240 voltsingle-phase utilization voltage used in the United States, or even the 250

volt/416 volt three-phase used in "European systems" is not equal to the task of

economically moving power more than a few hundred yards. The application of

these lower voltages for anything more than very local distribution at theneighborhood level results in unacceptably high electrical losses, severe voltagedrops, and astronomical equipment cost.

4. It is costly to change voltage level - not prohibitively so, for it is done throughout

a power system (that's what transformers do) - but voltage transformation is a

major expense, which does nothing to move the power any distance in and ofitself.

5. Power is more economical to produce in very large amounts. Claims by the

advocates of modern distributed generators notwithstanding, there is a significant

economy of scale in generation - large generators produce power more

economically than small ones. Thus, it is most efficient to produce power at a

few locations utilizing large generators.

6. Power must be delivered in relatively small quantities at low (120 to 250 volts)

voltage levels. The average customer has a total demand equal to only 1/10,000or 1/100,000 of the output of a large generator.

Multiple, Interconnected Levels

A power distribution system consists of four identifiable "levels:" sub-transmission,

substation, feeder, and service. Together, these comprise a highly interconnected

system with the electrical and economic performance at one level heavily dependent on

design, siting, and other decisions at another level. To a certain extent the T&D system




44 Chapter 1

must be planned and designed as a whole; its parts cannot be viewed in isolation,particularly if planners desire to minimize cost.

Discrete Equipment Sizes

In many cases equipment is available only in certain discrete sizes. For example, 69kV/12.47 kV transformers may be available only in 5, 10, 20, and 22 MVA sizes.Usually, there is a large economy of scale - the installed cost of a 20 MVA unit beingconsiderably less than two times that for a 10 MV A unit.

Dynamic Service Area Assignment Is a Powerful Planning Tool

Linearity of expansion costs by and utilization in the face of upgrades that are onlyavailable in discrete sizes is obtained by a rrang ing service areas. Given that a substationcan be built in only one of several discrete sizes, the planner obtains an economicalmatch of capacity to load by varying service areas. When reinforced with new capacityadditions, a substation might pick up load of su rround ing substations, effectivelyspreading the capacity add ition among several substations.

Cost to Upgrade Is Greater than Cost to Build

For example, one mile of a 12.47 kV, three-phase feeder using 600 MCM conductor (15

MW thermal capacity) might cost $150,000 to build, and one mile of 9 MW feeder (336MCM conductor) might cost only $110,000. But the cost to upgrade the 336 MCM

feeder to 600 MCM wire size at a later date would be about $130,000, for a cumulative

total of $240,000. Therefore, one aspect of minimizing cost is to determine size for

equipment not on the basis of immediate need, but by assessing the eventual need anddetermining whether the present worth of the eventual savings warrants the investmentin larger size now.

Peak Demands Are Non-Coincident

N ot all customer loads occur at the same time. This has a number of effects. First, peakload in different parts of the utility system may occur at different times. Second, thesystem peak load will always be less than the sum of the peak loads at any one level ofthe system - for example in more power systems the sum of all substation peak loads

usually exceeds system total peak by 3-8%. This diversity of peak loads means thatconsiderable attention must be paid to the pattern and timing of electric load ifequipment needs (and consequently costs) are to be minimized.

Losses Cost Can Be Significant

In some cases, the present worth of future losses on a line or heavily loaded transformer canexceed its total capital cost. In most cases, this does not happen. But in most cases, the

present worth of losses is greater than the difference in cost between most of the choicesavailable to the planner, meaning that losses are a major factor to be considered in

achieving overall least-cost design.

Reliability Was Traditionally Obtained Through Standards that

Specified Contingency Margins and Design Features

T&D reliability was traditionally "designed into" distribution systems by the use of

design, equipment, and operating "standards" — actually not standards in any legal orregulatory sense, but rather hard guidelines set up by the utility. These specifiedspecific ways to lay out and design facilities, defined what type and how equipment was





to be used, called for specific amounts of redundant capacity and specified how it was to

be used, and laid out operating policies and rules. They assured that satisfactory levels

of reliability were achieved (if not, then the "standards" were raised).

Reliability Is Increasingly Achieved by "Designing" to Specific

Targets Using Reliability-Based Engineering Methods

Standards-driven reliability design, the traditional approach, can achieve good reliability

performance, but such an approach often "overbuilds" or applies equipment and

configuration in less than an optimally useful manner. In some cases much more cost

effective use of funds can be accomplished by shifting to reliability-based standards

(numerical targets) and designing to those rather than employing hard and fast

guidelines (standards). Such planning is more complicated and costly but results in both

more assurance that reliability targets will be met and a savings in cost.

REFERENCES AND BIBLIOGRAPHY

A. V. Abbott, Electrical Transmission of Energy, Van N ostrand, N ew York, 1895.

R. Brown,ElectricDistribution System Reliability, Marcel Dekker, N ew York, 2002.

J. C. Das, Power Systems Analysis, Marcel Dekker, N ew York, 2002.

M. V. Engel et al., editors, Tutorial on Distribution Planning, IEEE Course Text EHO 361-6-PWR,

Institute of Electrical and Electronics Engineers, Hoes Lane, N J, 1992.

L. Philipson and H. L. Willis, Understanding Electric Utilities and De-Regulation, Marcel Dekker,

N ew York, 2000.

E. Santacana et al., ElectricalTransmission and Distribution Reference Book, ABB, Raleigh, N C.

Power Delivery Systems

Documents

Transcript of Power Delivery Systems